Shale Hydraulic Fracturing Research Articles

The in situ stress prediction of a fractured shale reservoir based on amplitude variation with angle and azimuth inversion: A case study from Southwest China

In situ stress estimation of a shale reservoir is critical for the design of shale hydraulic fracturing and wellbore stability analysis. Fractured shales have orthogonal anisotropy (OA) because of the presence of vertical fractures and lamination. However, the existing in situ stress estimation method mainly focuses on transversely isotropic media. To accommodate orthogonally anisotropic media, an in situ stress estimation method is developed by using amplitude variation with angle and azimuth inversion and linear-slip theory. First, an orthogonal anisotropic medium is introduced to characterize the fractured shale by using a linear-slip model, and then we formulate a reflection coefficient approximation for OA media to perform the seismic inversion. Next, a fracture weakness inversion strategy that incorporates the vertically transverse isotropic background is developed to obtain the stiffness matrix of the media. Finally, the in situ stresses of the OA medium are formulated by using a stress-strain relationship. Inversion tests and a real data application indicate that our method is effective.

Numerical analysis of hydraulic fracture propagation in deep shale reservoir with different injection strategies

Deep shale reservoirs are characterized by elevated breakdown pressures, diminished fracture complexity, and reduced modified volumes compared to medium and shallow reservoirs. Therefore, it is urgent to investigate particular injection strategies that can optimize breakdown pressure and fracturing efficiency to address the increasing demands for deep shale reservoir stimulation. In this study, the efficiency of various stimulation strategies, including multi-cluster simultaneous fracturing, modified alternating fracturing, alternating shut-in fracturing, and cyclic alternating fracturing, was evaluated. Subsequently, the sensitivity of factors such as the cycle index, shut-in time, cluster spacing, and horizontal permeability was investigated. Additionally, the flow distribution effect within the wellbore was discussed. The results indicate that relative to multi-cluster simultaneous fracturing, modified alternating fracturing exhibits reduced susceptibility to the stress shadow effect, which results in earlier breakdown, extended hydraulic fracture lengths, and more consistent propagation despite an increase in breakdown pressure. The alternating shut-in fracturing benefits the increase of fracture length, which is closely related to the shut-in time. Furthermore, cyclic alternating fracturing markedly lowers breakdown pressure and contributes to uniform fracture propagation, in which the cycle count plays an important role. Modified alternating fracturing demonstrates insensitivity to variations in cluster spacing, whereas horizontal permeability is a critical factor affecting fracture length. The wellbore effect restrains the accumulation of pressure and flow near the perforation, delaying the initiation of hydraulic fractures. The simulation results can provide valuable numerical insights for optimizing injection strategies for deep shale hydraulic fracturing.

An Optimal Model for Determination Shut-In Time Post-Hydraulic Fracturing of Shale Gas Wells: Model, Validation, and Application

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model.

Experimental investigation on mode I fracture characteristics of Longmaxi formation shale after cyclic thermal shock and high-temperature acid etching treatments

Fracture toughness is a key parameter for shale hydraulic fracturing design, which directly affects the fracture initiation pressure. In this paper, the influence of cyclic thermal shock and high-temperature acid etching on the Mode I fracture of Longmaxi Formation shale was investigated. The crack propagation was obtained by using acoustic emission (AE) and digital image correlation (DIC) techniques. Meanwhile, the fracture surface morphology and microstructure of the specimens were analyzed using white light interferometer and scanning electron microscope (SEM). The experimental results demonstrate that cyclic thermal shock severely degrades the nominal strength and fracture toughness of shale. The average fracture toughness is found to be only 0.67 MPa·m0.5, which accounts for a reduction of 25.9 %. AE analysis reveals that microfracture is the dominant mechanism, with the highest amplitude of AE source only 78 dB. The critical strain value of the fracture propagation zone (FPZ) is determined to be 1.35 ‰, and SEM images indicate that along-crystal fracture is the primary fracture mechanism. On the other hand, the shale specimen subjected to high-temperature acid-etching treatment exhibits an average fracture toughness of 0.86 MPa·m0.5, with the AE source amplitude reaching 86 dB. The critical strain value of the FPZ was measured to be 2.38 ‰. The fracture surface appears smooth and is mainly characterized by perforated-crystal rupture. The findings of this study not only enhance our understanding of shale mode I fracture toughness but also provide valuable insights for optimizing process parameters to reduce initiation pressure in deep shale formations.

A novel formulation of RNN-based neural network with real-time updating – An application for dynamic hydraulic fractured shale gas production forecasting

The Recurrent Neural Network (RNN) has found extensive application in production forecasting for fractured reservoirs, particularly excelling at accurately predicting self-regression in late-life prediction for wells with substantial historical data. However, forecasting for new wells or those with limited historical data presents greater challenges. The main difference lies in the insufficiency of historical data, which requires meaningful integration of a continuous production data stream to enhance prediction results. In the context of utilizing real-time data and continuously updating predictions, many existing formulations of RNN-based models in the literature either utilize inputs of sub-sequences instead of the entire sequence or require retraining of the entire model to handle new data and update the predictions. Therefore, we propose a novel prediction framework called Recurrent Updated Forecasting (RUF). This framework considers the entire time series structure, improves accuracy and training efficiency, and allows for prediction updates without retraining. In scenarios without production data, we employ a Radial Basis Function Network (RBFN) to initialize the process. Once more extended production history becomes available, it can be utilized to enhance prediction results. We present a case study based on both synthetic and field data from the Montney shale gas reservoir, considering different production-related features as inputs to predict gas production rates over a three-year period. The proposed method is evaluated using the P10, P50, and P90 values of the testing Root Mean Square Error (RMSE). The results demonstrate that our method outperforms existing approaches, exhibiting outstanding efficiency, reliability, and accuracy.

3D Integrated Model-Driven Work Flow Developed for Shale Hydraulic Fracturing

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212406, “3D Integrated G&G Model-Driven Mitigation Work Flow on Screenout, Frac Hits, and Casing Deformation in Ultradeep Shale Hydraulic Fracturing,” by Jianfa Wu and Bo Zeng, PetroChina, and Lipeng Wang, SLB, et al. The paper has not been peer reviewed. _ The Longmaxi shale gas play in China is unique because of multiple tectonic deformations in its geological history. While its hydraulic fracturing design has matured after a decade-long evolution, the success of every well cannot be ensured without considering heterogeneity. To address these challenges, a multidisciplinary team was formed to work on a pad; through the team’s efforts, designed proppant volume achieved zero casing deformations, fewer screenouts, and weaker fracture hits. The key to effective mitigation was continuous 3D geological and geomechanical (G&G) modeling through ongoing iterations with field data. Background The Longmaxi shale play in the Sichuan Basin is approximately 20 000 km2 and is buried between 2000 and 4500 m. This play has more than 10 trillion m3 of gas reserves and is made up of shallow and deep reservoirs. Currently, the operator has moved to the deeper Luzhou and Chongqing blocks buried at a depth greater than 3500 m. Nearly 200 horizontal wells per year are planned in the next 5 years. A fracture hit with tens of MPa increase was observed. Four casing failures were observed on 32 of the wells in this block, which made the unstimulated length more than 200 m and cost an extra $300,000 for interventions in each problematic well. While the risk of screenout, fracture hit, and casing deformation is common, risk levels vary for different reservoirs. No work flow is available that could be developed to identify and reduce these hazards. In this study, ultradeep shale gas at Pad X, buried almost 3900 m in the Luzhou Block, was selected to recognize and mitigate these risks (Fig. 1), where four wells were positioned 300 m apart. The lateral length of X-1 is roughly 1000 m, while the rest of the wells are roughly 1900 m in length. 3D G&G Modeling By combining seismic interpretation, seismic inversion, petrophysical analysis, and 1D geomechanical modeling while adhering to the Longmaxi-Wufeng Shale modeling technique used in neighboring blocks, the authors established a G&G model with dimensions of 40×40×0.5 m for the Luzhou Block. The pad model was refined to 8×8×0.5 m by using well logs to better characterize the variations in stage level. Natural Fractures. 3D surface seismic data was the only reliable source available to predict natural fractures in the shale and design the fracturing job, though the uncertainty was unavoidable. To display fault-/fracture-system characteristics, seismic attributes, including variance, ant tracking, and curvature were examined.

Combined Effect of In Situ Stress Level and Bedding Anisotropy on Hydraulic Fracture Vertical Growth in Deep Marine Shale Revealed via CT Scans and Acoustic Emission

The economic exploitation of unconventional gas and oil in deep shale relies closely on effective hydraulic fracturing stimulations. However, the fracturing operations of deep shale reservoirs face challenges of insufficient fracture growth and a rapid decline in productivity due to the increasing in situ stress level. In addition, the shale strata on the margin of the Sichuan Basin are frequently folded and faulted, and the change in bedding inclinations significantly complicates the process of hydraulic fracturing. The investigation of the combined effect of the in situ stress level and bedding anisotropy on the hydraulic fracture configuration is vital for fracturing engineering design. To analyze this, we conducted hydraulic fracturing tests on shale cores to simulate the hydraulic fracture initiation and growth from a horizontally positioned perforation. By using acoustic emission detection and CT scans, the influence of natural stress levels and the angle of the shale’s bedding on the process of hydraulic fracturing in shale and the resulting fracture geometry were analyzed. The results showed that the area of hydraulic fracture under a higher stress level (σ1 = 50 MPa, σ3 = 40 MPa) was about 13%~23% smaller than that created under the lower stress level (σ1 = 30 MPa, σ3 = 20 MPa) when the bedding angle was smaller than 60°. With the increase in bedding angle, the curves of the fracture area and fracture network index under two different stress levels presented similar decreasing trends. Also, the time from micro-crack generation to sample breakdown was significantly reduced when the bedding orientation changed from the horizontal to vertical position. The increasing stress level significantly increased the breakdown pressure. In particular, the fracturing of shale samples with bedding angles of 0° and 30° required a higher fluid pressure and released more energy than samples with larger bedding inclinations. Additionally, the measurement of the sample radial deformation indicated that the hydraulic fracture opening extent was reduced by about 46%~81% with the increasing stress level.

Impact of capillary pressure on micro-fracture propagation pressure during hydraulic fracturing in shales: An analytical model

Impact of capillary pressure on micro-fracture propagation pressure during hydraulic fracturing in shales: An analytical model

Microbial dynamics and biogenic methane production responses to the addition of glycine betaine in shales

Biogenic methane production depends on microbial community compositions in shale gas reservoirs, and glycine betaine plays an important role in methanogenic metabolic pathways. Previous studies have mainly focused on the microbial community dynamics in the water produced by shale hydraulic fracturing. Here, we used fresh shale as a sample and obtained the methane (CH4) and carbon dioxide (CO2) concentrations, microbial communities, and methanogenic functional gene numbers of solid and liquid groups in anaerobic bottles through gas chromatography, 16S rDNA sequencing (60 samples) and quantitative real-time PCR analysis in all culture stages. With glycine betaine addition, the total CH4 concentrations of the S1, S2 and Sw samples were 1.56, 1.05 and 4.48 times, while CO2 increased by 2.54-, 4.80- and 0.43-fold compared with samples without glycine betaine after 28 days of incubation, respectively. The alpha diversity was reduced when glycine betaine was added. The significant differences in bacterial community abundance at the genus level in samples with glycine betaine were Bacillus, Oceanobacillus, Acinetobacter, and Legionella. The bacterial and archaeal community changes implied that the addition of glycine betaine may promote CH4 production mainly by first forming CO2 and then generating CH4. The results of mrtA, mcrA, and pmoA gene numbers showed that the shale had great potential for producing methane. The addition of glycine betaine to shale changed the original microbial networks and increased the nodes and taxon connectedness of the Spearman association network. Our analyses indicate that the addition of glycine betaine enhances CH4 concentrations, causing the microbial network to be more complex and sustainable which supports the survival and adaptation of microbes in shale formations.

Numerical simulation on hydraulic fracture propagation in laminated shale based on thermo-hydro-mechanical-damage coupling model

The temperature of a deep shale reservoir may reach more than 100°C, and the effect of thermal shock on shale hydraulic fracturing has rarely not been considered in previous studies. Based on mesoscopic damage mechanics and the finite element method, a thermo-hydro-mechanical-damage (THMD) coupling model considering temperature, seepage, stress, and damage fields was constructed to investigate the effects of reservoir temperature, convective heat transfer coefficient ( h), in-situ stress difference and bedding plane angle ( αθ) on shale hydraulic fracturing. The results show that multiple hydraulic fractures (HFs) can occur under thermal shock and that HFs control the distribution of seepage, temperature, and stress fields. Reservoir temperature, in-situ stress difference and αθ are primary factors affecting hydraulic fracturing, whereas h is a secondary factor. When the reservoir temperature rises from 50°C to 150°C, the initiation and breakdown pressures decrease by 65.5% and 16.7%, respectively. HFs cross the bedding plane more easily, and fracture complexity is obviously enhanced. A higher h is favourable for slightly reducing the initiation and breakdown pressures, but it has little influence on the fracture complexity. Once the in-situ stress difference is low, there is a high fracture complexity, but HFs are more easily captured by bedding planes to limit the propagation of fracture height. When the in-situ stress difference is high, HFs are more likely to form bi-wing fractures. Whether αθ is too large or small, it is not conducive to improving the fracture complexity. In this study, when αθ is 30°, HFs and bedding planes intersect to form a fracture network. Essentially, thermal shock plays a key role in reducing the initiation pressure and forming multiple HFs during the fracturing process, and fracture propagation mainly depends on the injection pressure. The results can serve as reasonable suggestions for the optimization of shale hydraulic fracturing.

Investigation of thermal induced damage of deep shale considering in-situ thermal shock effects

Thermal shock caused by injecting cold fluids into hot underground formations, like deep shale hydraulic fracturing and geothermal extraction, is believed to cause deterioration of rock mechanical properties. Consequently, investigating thermally induced damage in deep shale under in-situ conditions is necessary to understand its mechanical behaviors. In this study, the structure and permeability characteristics of shale rock before and after different cooling modes are measured with the gas permeability measurement and CT-Scanning, the compression mechanical response of thermal shock specimens under in-situ conditions and its application prospects are discussed, and a statistical damage model is established eventually to predict deep shale mechanical constitutive. Results show that cooling rate was critical in the deterioration of rock properties, since micro-cracks were induced in water-cooling specimens, the physical properties of these samples were significantly enhanced. Moreover, rock mechanical properties were also deteriorated by thermal shock immensely and the deterioration was aggravated as the contact temperature difference increased. The understanding suggested that thermal shock was beneficial to increase fracture complexity and enhance shale seepage capacity, cryogenic fracturing techniques were applicable in enhancing stimulation response. Finally, the overall experimental and modeling methods introduced in this paper could well reflect the mechanical behaviors of deep shale considering thermal shock effects.

Hydraulic fracturing with low and high viscous injection mediums to investigate net fracture pressure and fracture network in shale of different brittleness index

The stimulation of shale reservoirs by hydraulic fracturing is required to recover trapped hydrocarbons. For effective stimulation, it is essential to study the mechanism of hydraulic fracturing in terms of fracture initiation and propagation in shale reservoirs. In this study, hydraulic fracturing experiments are carried out on three shale formations (Eagle Ford, Marcellus, and Mancos) to investigate the fracture initiation pressure and resultant fracture networks in different rock fabrics. Several parameters were evaluated in this respect, including rock heterogeneities in lamination and mineralogy, rock brittleness, the type of fracturing fluids, and various confinement conditions. The results show that rock heterogeneities profoundly affect the resultant fracture network in shale. Furthermore, the aperture, permeability, and complexity of the fracture network mainly depend on the structure and thickness of the laminate sets and the direction of the lateral well-bore concerning these discontinuities. The fracturing fluid substantially impacts the fracture initiation pressure and resultant fracture network in shale. Under constant fluid injection rates and confining conditions, the fracture initiation pressure with water resulted in higher net fracture pressure than higher viscous fluid (oil). However, the aperture and length of the fracture are significantly more significant in the latter case. The net pressure required to initiate fracture propagation is inversely related to the rock’s confinement pressure and brittleness index. A sharp decrease in net breakdown pressure is observed with both parameters. During hydraulic fracturing with water and oil, a consistent rise in the injection pressure is recorded. In contrast, sudden fluctuations are recorded with supercritical carbon dioxide (SC CO2) and SC CO2 foam injection. SC CO2 foam fracturing increased fracture initiation pressure compared to water and oil as injection mediums. An appreciable difference in fracture initiation pressure with SC CO2, SC CO2 foam, and water are 5023 psi, 6456 psi, and 4000 psi, respectively, at high conferment pressure (3500 psi). A comparison of Eagle Ford and Mancos shale hydraulic fracturing with different injection mediums shows that water produced complex fractures but unstable fractures in a Mancos shale due to water imbibition near fracture surfaces. In contrast, SC CO2 foam has produced open, complex, and stable fracture networks. Such open and stable fractures are mainly needed, so that embedment is avoided after achieving the required fracture network to maintain optimum fracture conductivity for the high production of hydrocarbons.

Experimental Study on the Effect of Bedding on the Fracture Process Zone of Shale

The conventional fracture in shale hydraulic fracturing belongs to the type-I fracture, and the size of the fracture process zone (FPZ) is an important index to measure the fracability of rock mass. This index is also one of the feasible entry points to study the complexity of the fracture network. In order to visually observe the type-I FPZ at the tip of shale fractures, and to study the relationship between the mechanical properties, the shape and size of the FPZ, and the bedding structure, Notched Semi-Circular Bend (NSCB) tests were conducted with three typical fracture direction-bedding orientations (splitter, arrester, divider). The digital image correlation (DIC) method was used to realize the intuitive observation of the real fracture process and the FPZ near the fracture tip. The test found that the FPZ of shale is narrow and long as a whole and is “flame-like”. The height-to-length ratio of the FPZ at the fracture tip determines whether bending and deflection happen between the new fracture and the prefabricated cracks when the fracture occurs. Most of the specimens often appear in the FPZ with a beaded high shear strain zone before the fracture, which is caused by the oblique communication of micro-cracks in the FPZ before the fracture. The appearance of a beaded zone of high shear strain indicates that macroscopic fracture is imminent. The research results can be used for the design of disaster early warning and prevention programs.

Stability of Natural Fractures under Disturbance of Hydraulic Fractures in Shale Reservoirs

Activating the natural fracture (NF) during hydraulic fracture (HF) propagation is a dominant factor for forming the complex fracture network in shale reservoirs. On basis of Renshaw and Pollard’s criterion for fracture intersection, we simulate the NF stability under dynamic disturbance of HF propagation in shale reservoirs with the cohesive zone model in ABAQUS and analyze the effects of various factors on the NF stability. The results show that activation of the NFs in shale hydraulic fracturing is controlled by NF length, NF density, intersection angle between the NF and the HF, horizontal principal stress difference, frac fluid viscosity, and injection rate. During HF propagation, the NF shorter than 0.2 m is less likely to be activated, and those longer than 0.5 m are more likely to be activated. As the NF density increases, not all NFs are activated. The NF at an approach angle larger than 10° is more likely to be activated. The NF is more likely to be activated under the low stress difference, and the NF cannot be activated when the stress difference is higher than 10 MPa. Both frac fluid viscosity and injection rate have effects on activation of NFs, and the NF is more likely to be activated by higher viscosity frac fluid and under higher injection rate. The results provide reference for fracture network stimulation in shale reservoirs.

Experimental Study on Hydraulic Fracturing of Bedding Shale Considering Anisotropy Effects.

The bedding plane formed by sedimentation makes shale anisotropic. To clarify the influence of bedding on the hydraulic fracturing of shale, the fracture characteristics of bedding shale were first clarified by conducting a hydraulic fracturing experiment on large-scale shale samples with different bedding angles. Subsequently, combined with the experimental results, based on the theory of elasticity, a new fracture initiation criterion for shale hydraulic fracturing considering its anisotropic characteristics was established. The influence of the bedding angle on the hydraulic fracture initiation pressure and initiation angle was analyzed. The results showed that the pump pressure curve during hydraulic fracturing can be divided into four stages: continuous pressurization, internal pressure drop, internal pressure attenuation, and internal pressure equilibrium stage. Corresponding to the four stages of the pump pressure curve, the evolution of hydraulic fracture has four processes: microfracture development, fracture initiation, fracture propagation, and fracture network equilibrium process. When the direction of the maximum principal stress is perpendicular to the bedding, a complex fracture network is easily formed. Depending on whether the bedding plane is open or not, the modes of interaction between the hydraulic fractures and bedding plane could be divided into eight types. Hydraulic fractures initiate in two ways: from the matrix and from natural fractures. During fracturing, with the increase in the bedding angle, the initiation pressure decreases gradually and the initiation angle decreases first and then increases. The knowledge gained in this study can provide data and theoretical support for drilling direction design and fracture pressure evaluation in the field of hydraulic fracturing.

An Experimental Analysis of Microcrack Generation during Hydraulic Fracturing of Shale

Hydraulic fracturing is commonly applied in the shale gas exploitation industry. However, the mechanical mechanism of permeability under fracturing has so far been unclear. In this study, an analysis of laboratory experiments on hydraulic fracture propagation and bedding plane reactivation in shale is presented. To investigate microcrack occurrence under fracturing, several small slices were collected from the fracture surface and scanned with a scanning electron microscope (SEM). It was found that observed microscopic microcracks could not be produced by fluid pressure as the latter generated compressive stresses at the site of microcracks. Rather, the microcracks were produced by tensile stress concentration in front of the propagating fracture. This implies that bedding plane reactivation was caused by fracture propagation along the plane. An analysis of microcrack lengths showed that shale exhibited anisotropy in fracture toughness with resistance to fracture propagation parallel to bedding planes being twice as small compared to resistance to fracture propagation in the direction normal to bedding planes.

Study on Effect of Perforation Orientation on Hydraulic Fracturing of Shale

The core technology to realize the development of unconventional oil and gas resources is the large-scale volume transformation of shale reservoirs, but volume fracturing is a complex physical and mechanical process, and its mechanism remains to be further studied. In this paper, starting from the current research status of shale volumetric fracturing, the perforation orientation of volumetric fracturing is numerically simulated by using the finite element software. The following conclusions are drawn: ① when the ground stress conditions are equal, with the increase of perforation angle, the maximum principal stress at the front of perforation decreases gradually; that is, when the perforation is along the horizontal minimum principal stress, the maximum principal stress at the front of perforation is the largest, which is most conducive to fracturing of shale reservoirs. ② When the perforation is along the direction of the horizontal minimum principal stress and the horizontal stress difference is zero, the smaller the horizontal stress, the greater the maximum principal stress at the front of the perforation. Therefore, the smaller the horizontal stress, the more conducive to the rupture of shale reservoirs. ③ When the perforation is along the horizontal minimum principal stress, the maximum principal stress at the front of the perforation increases with the increase of the horizontal stress difference. Therefore, the larger the horizontal stress difference, the more favorable for the fracture of shale reservoirs.

Occurrence and behavior of uranium and thorium series radionuclides in the Permian shale hydraulic fracturing wastes.

Over the last decade, there has been a rapid growth in the use of hydraulic fracturing (fracking) to recover unconventional oil and gas in the Permian Basin of southeastern New Mexico (NM) and western Texas. Fracking generates enormous quantities of wastes that contain technologically enhanced naturally occurring radioactive materials (TENORM), which poses risks to human health and the environment because of the relatively high doses of radioactivity. However, very little is known about the chemical composition and radioactivity levels of Permian Basin fracking wastes. Here, we report chemical as well as radiochemical compositions of hydraulic fracking wastes from the Permian Basin. Radium, the major TENORM of interest in unconventional drilling wastes, varied from 19.1 ± 1.2 to 35.9 ± 3.2Bq/L for 226Ra, 10.3 ± 0.5 to 21.5 ± 1.2Bq/L for 228Ra, and 2.0 ± 0.05 to 3.7 ± 0.07Bq/L for 224Ra. In addition to elevated concentrations of radium, these wastewaters also contain elevated concentrations of dissolved salts and divalent cations such as Na+ (31,856-43,000mg/L), Ca2+ (668-4123mg/L), Mg2+ (202-2430mg/L), K+ (148-780mg/L), Sr2+ (101-260mg/L), Cl- (5160-66,700mg/L), SO42- (291-1980mg/L), Br- (315-596mg/L), SiO2 (20-32mg/L), and high total dissolved solid (TDS) of 5000-173,000mg/L compared to background waters. These elevated levels are of radiological significance and represent a major source of Ra in the environment. The recent discovery of large deposits of recoverable oil and gas in the Permian Basin will lead to more fracking, TENORM generation, and radium releases to the environment. This paper evaluates the potential radiation risks associated with TENORM wastes generated by the oil and gas recovery industry in the Permian Basin.

Study on shale imbibition characteristics experiment from Longmaxi Formation of Southeastern Chongqing in Sichuan Basin

Shale belongs to low-porosity and low-permeability reservoir, so it is difficult for fluid to enter pores through displacement. However, in the process of shale hydraulic fracturing, most of the fracturing fluid does not flowback after entering strata. It indicates that reaction may take place when fluid enters into strata, resulting in low flowback rate of fracturing fluid. Imbibition experiment and physicochemical properties test show that there is imbibition effect in shale. There are two stages: one is the initial rapid water absorption, while the other is later osmotic water absorption. The first stage is affected by the seam network system, while the other stage is mainly affected by the content of clay minerals. As clay minerals swell by absorbing water, the original fracture network system gradually expands, and porosity grows, permeability improves and recovery rate increases. The physicochemical properties test shows that (1) imbibition is influenced by both capillary force and mineral components. The higher the clay content is, especially the content of chlorite and illite/smectite (I/S) , the stronger the imbibition capacity is. (2) Shale with strong imbibition capacity also has strong seam-making capacity, which not only provides convenience for hydraulic fracturing but is more conducive to exploitation.

The Investigation on Initiation and Propagation of Hydraulic Fractures in Shale Reservoir

Hydraulic fracturing is a necessary technique for shale gas exploitation. In order to have efficient stimulation treatment, a complex fracture network has to be developed, whereas with rich bedding planes and natural fractures, the mechanism of forming a fracture network is not fully understood and it is so tricky to predict propagation and initiation of hydraulic fracture. Therefore, in this paper, considering the strong anisotropy of shale reservoir, numerical simulation has been conducted to analyze fracture propagation and initiation on the basis of finite element and damage mechanics. Simulation results indicate that hydraulic fracture is not merely controlled by in situ stress due to strong anisotropy in shale. With plenty of bedding planes, hydraulic fracture tends to have initiation and propagation along the bedding plane. In particular, this influence becomes stronger with low strength and high development density of bedding planes. Additionally, in combination with natural fracture and bedding plane, the initiation point is usually on a natural fracture plane, causing relatively small breakdown pressure. In the process of fracture propagation, hydraulic fracture connects with natural fractures and bedding planes, forming dendritic bifurcation and more complicated paths. Numerical simulation proves that bedding plane and natural fracture are vital factors of hydraulic fracture. Compared to natural fracture, the bedding plane has a stronger impact on hydraulic fracture propagation. For the initiation of hydraulic fracture, natural fracture is the major effecting factor. The outcome of this study is able to offer theoretical guidance for hydraulic fracturing in shale.