Fault slippage and its permeability evolution during supercritical CO2 fracturing in layered formation

International audienceUnderstanding the hydromechanical responses of faults during supercritical CO2 fracturing is important for reservoir management and the design of energy extraction systems. As small faults are widespread in Chang 7 member of the Yanchang Formation, Ordos Basin, China, supercritical CO2 fracturing operation has the potential to reactive these undetected small faults and leads to unfavorable fracking fluid migrate. In this work, we examined the role of fault slippage and permeability evolution along a small fault connecting the pay zone and the confining formation during the whole process of fracturing and production. A coupled hydromechanical model conceptualized from actual engineering results was introduced to address the main concerns of this work, including, (1) whether the existence of a undetected small fault would effectively constrain the hydraulic fracture height evolution, (2) what the magnitude of the induced microseismic events would be and (3) whether the permeability change along the fault plane would affect the vertical conductivity of the confining formation and thus increase the risk for the fracturing fluid to leak. Our results have shown that the initial hydrofracture formed at the perforation and propagated upward, once it merged with the fault surface, the existence of an undetected small fault would effectively constrain the hydraulic fracture height evolution. As fracturing continued, further slippage spread from the permeability increase zone of high permeability to shallower levels, and the extent of this zone was dependent on the magnitude of the fault slippage. At the end of extraction, the slip velocity decreases gradually to zero and the fault slippage finally reaches stabilization. In general, undetected small faults in targeted reservoir may not be the source of large earthquakes. The induced microseismic events could be considered as the sources of acoustic emission events detected while monitoring the fracturing fluid front. Due to the limited fault slippage and lower initial permeability, the CO2 fracturing operation near undetected small faults could not conduct preferential pathway for upward CO2 leakage or contaminate overlying shallower potable aquifers

The influence of water-based drilling fluid on mechanical property of shale and the wellbore stability

AbstractBecause of high cost and pollution of oil-based drilling fluid, the water-based drilling fluid is increasingly used now. However, bedding planes and micro-cracks are rich in shale formation. When water-based drilling fluid contacts formation rock, it causes the propagation of crack and invasion of drilling fluid, which decrease shale strength and cause wellbore instability. In this paper, we analyzed influence of water-based drilling fluid on shale strength and failure mode by mechanics experiment. Based on those experimental results, considering the effect of bedding plane and drilling time, we established modeling of wellbore stability for shale formation. The result from this model indicates that in certain azimuth of horizontal well, collapsing pressure increases dramatically due to shale failure along with bedding plane. In drilling operation, those azimuths are supposed to be avoided. This model is applicable for predication of collapsing pressure in shale formation and offers reference for choosing suitable mud weight

Prediction of mechanical parameters for low-permeability gas reservoirs in the Tazhong Block and its applications

 A longitudinal distribution profile of the mechanical properties of the formations is important for the safe drilling, successful completion, and development of oil and gas reservoirs. However, the mechanical profile of the carbonate formations from the low-permeability gas reservoirs in the Tazhong (TZ) Block is hard to achieve due to the complex structural and lithological characteristics of the carbonates. In this paper, lab measurements are carried out to determine the physical and mechanical properties of the carbonate rocks of the Yingshan Formation in the TZ Block. Based on this, the relationships among density, the interval transit time and the mechanical parameters of the rocks in the TZ Block are constructed. The constructed relationships are then applied to the well-logging prediction of the mechanical profiles of the carbonate formations. The models are verified through the application to the two wells in the TZ Block, the results show that the relative errors in the predicted mechanical parameters are within 10% indicating the efficiency of the constructed models. The result of this study provides reasonable mechanical parameters for the exploration and development of the carbonate reservoirs in the TZ Block.Cited as: Wan, Y., Zhang, H., Liu, X., Yin, G., Xiong, J., Liang, L. Prediction of mechanical parameters for low-permeability gas reservoirs in the Tazhong Block and its applications. Advances in Geo-Energy Research, 2020, 4(2): 219-228, doi: 10.26804/ager.2020.02.1

The Similar Structure Method for Solving the Model of Fractal Dual-Porosity Reservoir

This paper proposes a similar structure method (SSM) to solve the boundary value problem of the extended modified Bessel equation. The method could efficiently solve a second-order linear homogeneous differential equation’s boundary value problem and obtain its solutions’ similar structure. A mathematics model is set up on the dual-porosity media, in which the influence of fractal dimension, spherical flow, wellbore storage, and skin factor is taken into cosideration. Researches in the model found that it was a special type of the extended modified Bessel equation in Laplace space. Then, the formation pressure and wellbore pressure under three types of outer boundaries (infinite, constant pressure, and closed) are obtained via SSM in Laplace space. Combining SSM with the Stehfest algorithm, we propose the similar structure method algorithm (SSMA) which can be used to calculate wellbore pressure and pressure derivative of reservoir seepage models clearly. Type curves of fractal dual-porosity spherical flow are plotted by SSMA. The presented algorithm promotes the development of well test analysis software

An Investigation of Fractal Characteristics of Marine Shales in the Southern China from Nitrogen Adsorption Data

We mainly focus on the Permian, Lower Cambrian, Lower Silurian, and Upper Ordovician Formation; the fractal dimensions of marine shales in southern China were calculated using the FHH fractal model based on the low-pressure nitrogen adsorption analysis. The results show that the marine shales in southern China have the dual fractal characteristics. The fractal dimension D1 at low relative pressure represents the pore surface fractal characteristics, whereas the fractal dimension D2 at higher relative pressure describes the pore structure fractal characteristics. The fractal dimensions D1 range from 2.0918 to 2.718 with a mean value of 2.4762, and the fractal dimensions D2 range from 2.5842 to 2.9399 with a mean value of 2.8015. There are positive relationships between fractal dimension D1 and specific surface area and total pore volume, whereas the fractal dimensions D2 have negative correlation with average pore size. The larger the value of the fractal dimension D1 is, the rougher the pore surface is, which could provide more adsorption sites, leading to higher adsorption capacity for gas. The larger the value of the fractal dimension D2 is, the more complicated the pore structure is, resulting in the lower flow capacity for gas

Analysis of Factors Influencing Three-Dimensional Multi-Cluster Hydraulic Fracturing Considering Interlayer Effect

This study establishes a three-dimensional cohesive model of multi-cluster hydraulic fracturing using finite element method (FEM). It fully considers the interaction between the interlayer and the reservoir and analyzes the key factors influencing fracture propagation. The results show that during the initial stage of hydraulic fracturing, the width of the edge fracture is greater than that of the mid fracture, while the situation is reversed for the fracture length. A larger cluster spacing leads to less interaction between fractures, while a greater number of clusters increases the interaction between fractures. With an increase in displacement, the lost fracturing fluid entering the formation enhances the interaction between fractures. An increase in elastic modulus results in a decrease in the width and height of edge fractures but an increase in their length, with little impact on mid fractures. As Poisson’s ratio increases, there is little change in the fracture morphology of edge fractures, while the width and height of mid fractures increase significantly. With an increase in permeability, the influx of fracturing fluid into the interlayer decreases, leading to a reduction in the interaction between fractures. Finally, the study analyzes and discusses the impact of these parameters on the SRV (stimulated reservoir volume) in both the reservoir and the interlayer. These findings provide new insights for hydraulic fracturing and contribute to improving its productivity

Numerical Investigation of Hydraulic Fracture Propagation Morphology in the Conglomerate Reservoir

The random distribution of gravels makes the conglomerate reservoir highly heterogeneous. A stress concentration occurs at the gravel-matrix interfaces owing to the embedded gravel and affects the local mechanical response significantly, making it difficult to control and predict hydraulic fracture (HF) propagation. The mechanism of HF propagation in conglomerate reservoirs remains unclear; thus, it is difficult to effectively design and treat hydraulic fracturing. Based on the global pore-pressure cohesive zone element (GPPCZ) model method, a two-dimensional (2D) fracture propagation model with flow-stress-damage (FSD) coupling was established to investigate HF nucleation, propagation, and coalescence in conglomerate reservoirs. This model was experimentally verified, and fractal theory was introduced to quantify the complexity of fracture morphology. The microscale interactions of the gravel, matrix, and interface have been taken into consideration during simulating HF propagation accurately in macroscale. The influence of the mechanical properties of gravel, matrix, matrix-gravel interface, and reservoir stress distribution state, on HF morphology (HF length, stimulated reservoir square, and HF complexity morphology), was investigated. Finally, the main factors affecting fracture propagation were analyzed. It was revealed that the difference between the mechanical properties of the gravel and the matrix in the conglomerate rock will affect the geometry of HF to varying degrees. The local behavior of fracture propagation is obviously dominated by the elastic modulus, tensile strength, and the strength for the matrix-gravel interface. However, the propagation of HF at the whole scale is mainly dominated by the horizontal stress state, including the minimum horizontal stress and horizontal stress difference. In addition, the difference in horizontal stress significantly affects the fracturing patterns (deflection, bifurcation, and penetration) when HF encounters gravel. In this study, a simulation method of HF propagation in conglomerate reservoirs is introduced, and the results provide theoretical support for the prediction of HF propagation morphology and plan design of hydraulic fracturing in conglomerate reservoirs

The Influence of Bedding Planes and Permeability Coefficient on Fracture Propagation of Horizontal Wells in Stratification Shale Reservoirs

The complexity of hydraulic fractures (HF) significantly affects the success of reservoir reconstruction. The existence of a bedding plane (BP) in shale impacts the extension of a fracture. For shale reservoirs, in order to investigate the interaction mechanisms of HF and BPs under the action of coupled stress-flow, we simulate the processes of hydraulic fracturing under different conditions, such as the stress difference, permeability coefficients, BP angles, BP spacing, and BP mechanical properties using the rock failure process analysis code (RFPA2D-Flow). Simulation results showed that HF spread outward around the borehole, while the permeability coefficient is uniformly distributed at the model without a BP or stress difference. The HF of the formation without a BP presented a pinnate distribution pattern, and the main direction of the extension is affected by both the ground stress and the permeability coefficient. When there is no stress difference in the model, the fracture extends along the direction of the larger permeability coefficient. In this study, the in situ stress has a greater influence on the extension direction of the main fracture when using the model with stress differences of 6 MPa. As the BP angle increases, the propagation of fractures gradually deviates from the BP direction. The initiation pressure and total breakdown pressure of the models at low permeability coefficients are higher than those under high permeability coefficients. In addition, the initiation pressure and total breakdown pressure of the models are also different. The larger the BP spacing, the higher the compressive strength of the BP, and a larger reduction ratio (the ratio of the strength parameters of the BP to the strength parameters of the matrix) leads to a smaller impact of the BP on fracture initiation and propagation. The elastic modulus has no effect on the failure mode of the model. When HF make contact with the BP, they tend to extend along the BP. Under the same in situ stress condition, the presence of a BP makes the morphology of HF more complex during the process of propagation, which makes it easier to achieve the purpose of stimulated reservoir volume (SRV) fracturing and increased production

Investigation on the Influence of Water-Shale Interaction on Stress Sensitivity of Organic-Rich Shale

Shale reservoirs are characterized by low permeability and natural fractures. In the process of reservoir development, the working fluid enters the reservoir. This may result in the formation of new fractures or expansion of natural fractures. When shale reservoirs are exploited, the fluid pressure in the fracture or pore is reduced. This destroys the stress balance of the reservoir, produces stress sensitivity damage, and reduces the reservoir permeability. Organic-rich shale from the Yanchang Formation, Chang 7 Member of the Ordos Basin, was selected for core flow experiment with helium. The effects of the type of brine, salinity, and soaking time on the stress sensitivity of an organic-rich shale reservoir were investigated. The acoustic characteristics were also investigated to study the effect of interactions between water and shale on stress sensitivity. The experimental results demonstrate that the interactions of water and shale increase the permeability of shale and reduce its stress sensitivity. Furthermore, when the permeability of the shale is excessively low, the stress sensitivity is high. In the acoustic studies, a higher attenuation coefficient of the acoustic wave corresponds to a larger variation in the shale structure and thus a larger permeability of the shale and smaller stress sensitivity coefficient. Whereas there is no apparent effect of the salt water type on the stress sensitivity, higher salinity levels cause higher stress sensitivity. After reacting with 15000 mg/L brine, the stress sensitivity coefficient of shale did not decrease significantly compared with that before action, all of which were above 0.97. However, after reacting with distilled water or 5000 mg/L brine, the stress sensitivity coefficient of shale decreased significantly, and all of them decreased to less than 0.9. Longer water exposures, corresponding to an increased duration of water-shale interactions, result in higher impacts on the stress sensitivity of shale. After 6 hours of shale-brine interaction, the stress sensitivity coefficient of shale is as high as 0.93, while after 48 hours of shale-brine interaction, the stress sensitivity coefficient of shale is reduced to 0.88. This study provides a highly effective reference with regard to the influence of the working fluid on the reservoir during drilling operations and the study of reservoir characteristics after fracturing