Horizontal Principal Stress Research Articles

Roof Fractures of Near-Vertical and Extremely Thick Coal Seams in Horizontally Grouped Top-Coal Drawing Method Based on the Theory of a Thin Plate

During the mining process of the near-vertical seam, there will be movement and collapse of the “roof side” rock layer and the “overlying coal seam,” as well as the emergence of the “floor side” rock layer roof which is more complicated than the inclined and gently inclined coal seams, which causes problems with slippage or overturning damage. With the increase of the inclination of the coal seam, the impact of the destruction of the immediate roof on the stope and roadway gradually becomes prominent, while the impact of the destruction of the basic roof on the stope and the roadway gradually weakens. The destruction of the immediate roof of the near-vertical coal seam will cause a large area of coal and rock mass to suddenly rush to the working face and the two lanes, resulting in rapid deformation of the roadway, overturning of equipment, overturning of personnel, and even severe rock pressure disaster accidents, all of which pose a serious threat to coal mine safety and production. It is necessary to carry out research on the mechanical response mechanism of the immediate roof of near-upright coal seams, to analyse the weighting process of steeply inclined thick coal seam sub-level mining. A four fixed support plate model and top three clamped edges simply supported plate model for roof stress distribution are established before the first weighting of the roof during the upper and lower level mining process. The bottom three clamped edges simply supported plate model and two adjacent edges clamped on the edge of a simply supported plate model are established for roof stress distribution before periodic weighting of the roof during the upper and lower level mining process. The Galerkin method is used to make an approximate solution of deflection equation under the effect of sheet normal stress, and then roof failure criterion is established based on the maximum tensile stress strength criterion and generalized Hooke law. This paper utilizes FLAC3D finite element numerical simulation software, considering the characteristics of steeply inclined thick coal seam sub-level mining. It undertakes orthogonal numerical simulation experiment in three levels with different depths, coal seam angles, lateral pressure coefficient, and orientation of maximum horizontal principal stress, and translates roof stress of corresponding 9 simulation experiment into steeply inclined roof normal stress. We conclude that the distribution law of normal stress along dip and dip direction of a roof under the circumstance of different advancing distances and different sub-levels. The caving pace of first weight and periodical weight were counted under the effect of the roof uniform normal stress. It can better predict the weighting situation of the working face and ensure the safe, efficient, and sustainable mining of coal mines.

Prediction method and distribution characteristics of in situ stress based on borehole deformation—A case study of coal measure stratum in Shizhuang block, Qinshui Basin

A geometric equation of borehole deformation under stress was deduced based on the basic theory of elasticity. Subsequently, we established the quantitative relationship between the in situ stress and geometrical parameters of borehole deformation. Furthermore, we proposed an in situ stress prediction model based on borehole deformation. Additionally, numerical simulations of borehole morphology in different lithologies under in situ stress were conducted to analyze the deformation effect. Logging parameters that are sensitive to the shear wave time difference, such as longitudinal wave time difference, density, and natural gamma radiation, were selected for training using an artificial neural network (ANN) to predict the shear wave time difference. The results demonstrated that 1) combining the theoretical derivation and numerical simulation, the borehole geometry under stress was quasi-elliptic, and 2) compared with the existing shear wave time difference curve, the predicted geometry by the ANN was consistent with the actual geometry. Consequently, compared with the tested data from acoustic emission, the overall error of the in situ stress predicted using the new method was less than 9.2%. Moreover, the accuracy of the coal seam was the highest, wherein the average errors of the maximum and minimum horizontal principal stresses were 2.01 and 2.56%, respectively, which confirms the feasibility of the proposed method.

Mechanistic Study on the Influence of Stratigraphy on the Initiation and Expansion Pattern of Hydraulic Fractures in Shale Reservoirs

The unique depositional characteristics of shale reservoirs lead to the extreme development of shale laminae, natural fractures, and other weak surfaces, which have an important influence on the hydraulic fracture extension behavior and the final fracture geometry. Therefore, because the deep shale laminar development and hydraulic fracture interaction theory and influence mechanism are not clear, this paper focuses on the analysis of the influence law of the ground stress difference, laminar surface cementation characteristics, laminar surface dip angle, and other factors on the hydraulic fracture extension pattern in shale reservoirs based on the cohesive unit method. Numerical calculation results show that (1) the hydraulic cracks are first expanded along the direction perpendicular to the minimum horizontal principal stress after starting to crack from the injection point and then turn to expand along the side of the laminar surface when encountering the laminar surface. (2) Three laminar dips of 5°, 30°, and 60° were compared and found. A certain ground stress difference is conducive to communicating more laminated joints and forming a more complex fracture network, while too large of a ground stress difference reduces the complexity of artificial fractures. (3) The smaller the inclination of the laminate surface is, the greater the positive stress it is subjected to, the more difficult it is for the laminate joints to undergo shear slip, and the more difficult it is to open. (4) Under the same ground stress combination state and laminar surface inclination, laminated cementation strengths of 2 and 0.5 MPa were compared, and it was found that the lower the cementation strength of the laminate is, the more likely the hydraulic fracture will be activated to shear slip damage. At the same time, the reliability of the simulation study on the effect of laminar surfaces on hydraulic fracture extension based on the cohesive unit method is verified by combining with the corresponding indoor hydraulic physical model test, which provides a reference for the accurate description of the interaction mechanism between laminar surfaces and hydraulic fractures.

Simulation study on the deflection and expansion of hydraulic fractures in coal-rock complexes

The physical difference and structural weak surface of coal-rock complexes greatly influence the morphology of hydraulic fractures (HFs). This study aims to explore the law of deflection and expansion of HFs in coal-rock complexes under different stress conditions. First, a theoretical model for HF deflection in coal-rock complexes was derived. Besides, a numerical model for HF expansion in coal-rock complexes was established based on the traction–separation criterion, the cohesion embedding method and the finite element method for fracture expansion. With the aid of the established model, the laws of morphology and induced stress field evolutions during HF expansion were studied. The following conclusions were drawn. When the HF is closer to the interface, the effect of physical difference is more notable, and the HF is more likely to expand along the coal seam. As the difference between the maximum horizontal principal stress and the vertical ground stress decreases from 8 MPa to 0 MPa, the coal-rock complexes experience HF expansion in the horizontal direction, secondary fracture generation in the Z-axis direction, and HF deflection to the interface in the -Z-axis direction in turn. During HF expansion, a stress difference of about 19 MPa exists between the fracture tip section and the interface, which is favorable for HF initiation and expansion. The effect of physical difference between coal and rock leads to the formation of an induced stress field, which causes a 3–4 times difference in the displacement values in different areas during HF expansion. The abovementioned main causes of HF deflection can provide reference for the design and application of the hydraulic fracturing technology for complex formations with different lithologies.

Proactive stress interference mechanism and its application in the Mahu oil area, Junggar basin

There exists a large horizontal principal stress difference (11–38 MPa) in the tight conglomerates in the Mahu oil area, China. It is difficult to form a complex fracture network via hydraulic fracturing under these conditions. To improve reservoir stimulation, the fracture formation mechanism of the complex conglomerate fracture networks was explored. Based on the geomechanics theory of fracture formation, the mechanism of the “stress wall” formed by fracturing in horizontal wells was analyzed in this paper. The inhibitory effect of the stress wall on the formation of tensile and shear fractures was studied. The reason for the decrease in the stress difference coefficient caused by fracturing fluid was analyzed through numerical simulation, which suggested that the complexity of a fracturing network is mainly controlled by the interference of externally applied stress and the reduction in the coefficient of internal stress difference. In this paper, innovative technologies were developed by proactively introducing stress interference in the application of the Ma131 small-well-spacing pilot area. The core technologies include optimization of the 3-D staggered small-well-spacing pattern, and synergetic optimization of multiple elements and zipper fracturing. The positive effects of proactive stress interference on improving fracturing volume, reserve utilization rate and recovery were discussed. Based on the concept of proactive stress interference, the “serial fracturing mode” of horizontal wells was proposed to reduce drilling and fracturing interference and improve the development effect.

Effect of In-Situ Stress on Hydraulic Fracturing of Tight Sandstone Based on Discrete Element Method

The tight sandstone reservoir in the Qianfoya formation of well PL-3 of the Puguang gas field in Sichuan, China, obtained a high-yield gas flow after a volume fracturing treatment. However, the stimulated reservoir volume (SRV), fracture morphology, scale and formation law still remain unclear. Based on particle flow discrete-element theory in this paper, we carried out a few trials of the Brazilian splitting test, uniaxial compression and triaxial compression of rock mechanics. Meanwhile, the research also testified to the conversion relationship between macroparameters and microparameters, established the numerical simulation on hydraulic fracturing through PFC2D discrete element software, and finally analyzed the influence of difference coefficients on the fracturing effect, in terms of different in-situ stresses. The conclusions are as follows: firstly, the influence of in-situ stress is essential for the direction, shape and quantity of fracture propagation, and the fractures generated by hydraulic fracturing are mainly tension fractures, accounting for over 90% of the total longitudinal fractures. Secondly, it is indicated that when the difference coefficient is small in the in-situ stress, the fractures formed by hydraulic fracturing expand randomly around the wellbore. When the difference coefficient Kh of in-situ stress is above 0.6, the development of hydraulic fractures is mainly controlled by in-situ stress; as a result, the fractures tend to expand in the vertical direction of the minimum horizontal principal stress and the fracture shape is relatively singular. When the difference coefficient of in-situ stress was 0.3, in total, 3121 fractures were generated by fracturing, and the fractal dimension D value of the fracture network complexity was 1.60. In this case, this fracturing effect was the best and it is the easiest to achieve for the purpose of economical and effective development on large-scale volume fracturing.

Damage of reservoir rock induced by CO2 injection

The study of reservoir rock damage induced by gas injection is of great significance to the design of reservoir stimulation and the improvement of oil and gas recovery. Based on an example horizontal well in the Hudson Oilfield of the Tarim Basin and considering the multi-physics coupling effects among high-pressure fluid, rock deformation, and damage propagation during CO 2 injection, a three-dimensional finite element model for CO 2 injection in deep reservoir considering seepage-stress-damage coupling was developed. The evolution of reservoir rock damage under different CO 2 injection conditions was systematically investigated. The results show that tensile damage and shear damage are concentrated in the vertical direction and the horizontal maximum compressive principal stress direction, respectively, and the tensile damage is the main damage mode. At higher CO 2 injection rate and pressure, the damaged areas near the wellbore are mainly distributed in the direction of the maximum compressive principal stress, and the development of the damaged area near the wellbore will be inhibited by the formation and evolution of far-field damage. CO 2 injection aggravates the extension of tensile damage, but inhibits the initiation of shear damage, and eventually leads to the gradual transition from shear damage to tensile damage. Under the same injection conditions, CO 2 injection has superior performance in creating rock damage compared with the injection of nitrogen and water. The results in this study provide guidance for enhanced oil recovery in deep oil and gas reservoirs with CO 2 injection.

New prediction method of horizontal principal stress of deep tight reservoirs

As the tight reservoir of Lucaogou Formation in Jimsar sag is characterized as large burial depth and poor physical properties, hydraulic fracturing technology is greatly needed to increase the production. Firstly, based on elastic theory, the borehole displacement formula under stress is derived, then the borehole quasi-ellipse characteristic model is proposed, on this basis, the in-situ stress prediction model based on borehole deformation is constructed. Secondly, the force analysis of diamond bit during drilling is performed, and the continuous prediction formula of elastic modulus based on weight on bit (WOB) and torque parameters is derived. Combined with these two steps, a new model of continuous in-situ stress prediction based on borehole deformation and drilling parameters is established. Compared with the values measured by the acoustic emission method in the laboratory, the deviation between the predicted in-situ stress values and those measured by the acoustic emission method is less than 4%, which meets the accuracy requirements of the fracturing in the oil field. The prediction results show that the minimum horizontal principal stress of Lucaogou Formation is 51.1–62.7 MPa, and the maximum horizontal principal stress is 58.9–69.1 MPa, respectively. The maximum horizontal principal stress direction is NW–SE direction with an angle of about 159°. The results show that the fracture direction in the study area is in accordance with the present in-situ stress direction, which is beneficial to the secondary reconstruction of natural fractures and keeps good opening property of fractures. This study provides a theoretical basis for in-situ stress prediction and compressibility evaluation of tight reservoir.

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.

Study on hydraulic fracturing initiation model based on nonlinear constitutive equation

In this article, the nonlinear characteristics of rock deformation were characterized based on the Power-enhanced constitutive equation, and the piecewise nonlinear constitutive equation was established by using the piecewise approximation method. Based on the constitutive equation, an elastic-plastic stress field model around wells was established to analyze the stress field around wells during hydraulic fracturing. The initiation mode of elastic-plastic formation was analyzed and optimized. The results showed that the plastic yield of rock was determined by the in-situ stress field and the initial yield stress. The smaller the yield stress was, the greater the in-situ stress was, and the more easily the plastic yield occurred. Under the combined of rock mechanics parameters and in-situ stress, the tension failure occurred when the wellbore was under elastic state, and there were two failure modes of plastic tension failure and plastic shear failure after plastic state. The initiation directions of elastic tension, plastic tension, and plastic shear failure were the direction of maximum horizontal principal stress, while there was a failure angle between the fracture plane and the maximum horizontal principal stress under the shear failure.

Factors Controlling the Hydraulic Fracture Trajectory in Unconventional Reservoirs

The morphology of hydraulic fracture is affected by many factors. In previous studies, due to the heterogeneity of rock samples and the limitations of sample size, influence degree of various factors on fracture deflection angle has not been well distinguished in laboratory experiments. Based on the boundary element method, we established a mathematical model to study the factors controlling the morphology of hydraulic fracture. Simulation results show that with increasing injection pressure, the radius of the fracture curvature increases. When the difference between the injection pressure and the maximum principal stress is 5 times the ground stress difference, the influence of in situ stress on hydraulic fracture deflection can be ignored. Hydraulic fracture deflection angle was relatively larger when considering the viscosity of the fracturing fluid. When stress difference is too small or the injection pressure is too big, the deflection angle of fracture is easy to fluctuate during initial propagation. Too large Young’s modulus and too small Poisson’s ratio will inhibit the fracture deflection and cause a narrower width of fracture. The effect of Poisson’s ratio on fracture aperture is less than 1 mm. When perforation angle is perpendicular to maximum horizontal principal stress, the fracture width first increases rapidly and then gradually decreases from heel to tip. The influence degree of each factor on fracture deflection is ranked: stress difference of in-situ stress is the biggest, followed by injection pressure and perforation angle. This study is of great significance for the control of hydraulic fracture morphology and the further improvement of fracturing effect.

In Situ Stress Distribution in Cretaceous Ultra-Deep Gas Field From 1D Mechanical Earth Model and 3D Heterogeneous Geomechanical Model, Kuqa Depression, Tarim Basin, NW China

The Kuqa Depression boasts rich cretaceous ultra-deep hydrocarbon resources. However, it is in complex geological conditions. At present, sufficient understandings on the in situ stress distribution and influencing factors are lacking, which restricts the process of hydrocarbon exploitation. Therefore, in this study, the Bozi gas field is selected as an example, and a 1D mechanical earth model (1D MEM) is established with the drilling data and logging data through the geomechanical method to clarify the in situ stress distribution of the wellbore. A 3D heterogeneous geomechanical model (3D HGM) is established with the constraint of 1D HEM to clarify the distribution characteristics of the 3D in situ stress field in the Bozi gas field and discuss its influencing factors. The results show that: 1) the Bozi gas field is in an extremely strong in situ stress condition with high stress values. The minimum horizontal principal stress (Sh) of the cretaceous system is 153∼180 MPa, and the maximum horizontal principal stress (SH) is nearly 200 MPa; 2) the in situ stress in the Bozi gas field has obvious vertical stratification characteristics, which can be divided into three stress sequences of “low–high–low”, with great differences in interlayer stress; 3) the in situ stress distribution of the Bozi gas field is greatly affected by the types of faulted anticline. Different types indicate different stress distribution; 4) within the influence range of overthrusts, the in situ stress in the footwall is lower than that of the hanging wall. The greater the fault offset, the greater the in situ stress difference between the hanging wall and footwall. Moreover, the lower the stress in the footwall, the higher is the degree of overthrust, and the larger is the range of footwall stress area; and 5) the means of highly deviated wells is more helpful to the Bozi gas field for hydrocarbon exploitation.

Experimental study on hydraulic fracture propagation behavior on dolomite rocks with open-hole completion

To determine to discuss fracture mechanisms and the possible encounter problems in open-hole fracturing in tight carbonation, tri-axial hydraulic fracturing experiments were performed on dolomites with acoustic emission monitoring. The results demonstrate that a complex fracture network is difficult to create in most cases even if the dolomite has high brittleness. In general, fractures likely have three types of fracture geometry, namely, bi-wing fractures, local multiple fractures and complex multiple fractures. However, even if multiple fractures can be initiated with open-hole completion, they still can finally merge into one dominant hydraulic fracture (HF). Branch fractures can be observed with low horizontal stress difference and low fluid viscosity. The breakdown pressure on dolomites has a positive relationship with the high fluid viscosity and fluid injection rate, but a negative relationship with the high horizontal principal stress difference. The existence of natural fractures and critical engineering parameter differences should simultaneously contribute to the ratio of branch fracture and diverge fracture. The microscopic observation results reveal that natural fractures that are infilled with mixed calcite minerals are more likely activated due to the lower strength of these minerals, and the main HF is arrested with a natural fracture that is infilled with high-strength calcite minerals. The separation of calcite clusters may exert competing effects on the fracture conductivity. On one hand, the debonded calcite clusters can seal and plug open HFs and reduce the fracture conductivity if the fracture width is not substantial. On the other hand, a calcite cluster can be a type of natural self-proppant to sustain long-term conductivity. The selection of open-hole completion in dolomite selection increases the risks of wellbore deformation but no serious wellbore collapse can be observed. Thus, hydraulic fracturing using open-hole completion can be recommended in dolomite reservoir development if the fracture height containment problem is not a critical issue.

Hydraulic fractures simulation in non-uniform stress field of horizontal shale gas well

Shale reservoirs have low porosity and ultra-low permeability. A significant increase in gas well production requires horizontal well fracturing. In this view, the propagation behavior of hydraulic fractures during the fracturing process is critical to the effect of shale gas reservoir stimulation. However, some shale formations have developed faults and the in-situ stress field has a non-uniform distribution. Also, the maximum horizontal principal stress direction varies with the spatial position, and non-planar deflection propagation behavior in hydraulic fractures is possible. The purpose of this article is to reveal the effect of the development of faults in the shale formation on the propagation of hydraulic fractures. A calculation model for the non-uniform tectonic stress field near the fault was established, and on this basis, we constructed a shale gas horizontal well-staged multi-cluster fracturing hydraulic fracture deflection propagation model under the influence of faults. Furthermore, the fracture propagation law was simulated and analyzed in the presence of a non-uniform in-situ stress field. The findings demonstrate that hydraulic fractures near the strike-slip fault tend to run parallel to the fault direction, whereas hydraulic fractures near the normal fault tend to run perpendicular to the fault direction. The greater the fault throw and the greater the hydraulic fracture propagation deflection angle, the closer the hydraulic fracture is to the fault. The deflection behavior of hydraulic fractures increases flow resistance in the fracture, and proppant transport does not flow smoothly, increasing the difficulty and risk of the fracturing operation. The findings of this study could provide an important theoretical foundation for the design of staged multi-cluster fracturing of horizontal wells near faults in shale formations.

Parameter Sensitivity Analysis of the Hydraulic Fracture Growth Geometry in a Deep Shale Oil Formation: An Experimental Study

The depth of shale oil of Fengcheng Formation in Mahu of Junggar Basin, China, is 4500-5000 m. The horizontal principal stress difference of deep shale reservoir is high, which makes it difficult to form complex fractures during fracturing reconstruction. In order to fully understand the law of hydraulic fracture propagation in the formation during fracturing construction, the anisotropy characteristics and basic reservoir physical parameters (mineral composition and rock strength parameters) of rock were obtained through mineral composition test and indoor rock mechanics test (Brazil splitting test), and it was found that the heterogeneity was strong. The true triaxial fracturing simulation experimental system is used to carry out experimental research on full-diameter core rock samples, and the propagation patterns of hydraulic fractures under the influence of different geological factors (in situ stress difference and natural fractures) and engineering factors (pumping rate and fracturing fluid viscosity) are compared and analyzed. The results show that the in situ stress is the most important factor affecting fracture propagation, which determines the direction and shape of fracture propagation. The natural weak surface (lamina/bedding and natural fractures, etc.) in shale reservoir is an important reason for complex fractures. The nature of the weak plane, occurrence, and in situ stress jointly determine whether the fracture can extend through the weak plane. With the increase of pumping rate (18 mL/min to 30 mL/min), the ability of hydraulic fractures to penetrate layers is continuously enhanced. The horizontal principal stress difference of deep shale reservoir is high, and the low viscosity fracturing fluid (10 mPa·s) tends to activate the horizontal bedding, while the high viscosity fracturing fluid (80 mPa·s) tends to directly penetrate the bedding to form the vertical main fracture. Therefore, the fracturing technology of alternating injection of prehigh viscosity fracturing fluid and postlow viscosity fracturing fluid can be adopted to maximize the complexity of fracturing fractures in deep shale reservoirs. The research results are designed to provide theoretical guidance for prediction of hydraulic fracturing fracture propagation in shale reservoir and have certain reference significance for field construction.

Multiscale Sensitivity Analysis of Hydraulic Fracturing Parameters Based on Dimensionless Analysis Method

Abstract The optimal design of hydraulic fracturing parameters is the key to commercial exploitation of unconventional reservoirs. Hydraulic fracturing test is one of the main methods for optimizing fracturing parameters. It is known that scale effect exists between laboratory experiments and field treatments of hydraulic fracturing. However, studies on how to eliminate the scale effect are rarely reported. In this work, we conduct sensitivity analysis on rock mechanical parameters and fracturing parameters at different scales by using the dimensionless analysis method. The initiation and propagation process of field hydraulic fracturing is reproduced through laboratory tests, and fracturing parameters are analyzed by using numerical simulation. Our results show that the fracture propagation in the laboratory is inconsistent with that in the field fracturing. The fracture initiation and propagation in the field can be reproduced in experiments by using samples with high modulus and low toughness as well as high-viscosity fracturing fluid. Microcracks are created before the breakdown pressure is reached, and hydraulic fractures extend perpendicular to the direction of the minimum principal stress. The Carter’s leak-off coefficient has little effect on breakdown pressure and propagation pressure, but the injection rate and the horizontal principal stress have significant effects on breakdown pressure. This study provides a theoretical basis and guidance for the design of fracturing parameters both in the laboratory and in the field.

A Random‐XFEM technique modeling of hydraulic fracture interaction with natural void

In this paper, a Random-XFEM technology was employed to simulate hydraulic fracture interaction with the natural void in a random field of Young's modulus. The random distribution of Young's modulus is characterized by random field theory, while the stress and pressure fields fracturing were solved by the extended finite element method. And a Random-XFEM iteration algorithm was proposed to solve the hydraulic fracture propagation problem. Then the proposed model was verified against the KGD model and numerical study. A series of numerical examples were presented to analyze the interaction mechanism of hydraulic fracture and void in a random field. The numerical results show that the random field of Young's modulus has a great impact on the hydraulic fracture propagation path. Under the random distribution of Young's modulus, the hydraulic fracture would deviate from the direction of maximum horizontal principal stress. And the random field parameters (Young's modulus mean and point variance) have different effects on the hydraulic fracture propagation path. Also, the interaction patterns of hydraulic fracture and void are greatly affected by random fields.

Development Characteristics of Silurian Strike-Slip Faults and Fractures and Their Effects on Drilling Leakage in Shunbei Area of Tarim Basin

In recent years, the Ordovician fault-controlled fracture-cavity reservoirs developed in the basement strike-slip fault zone in the Shunbei area of the Tarim Basin has achieved major breakthroughs. However, during the drilling process of the strike-slip fault zone in the Shunbei area, the problem of mud leakage in the frequently interbedded Silurian sandstone and mudstone strata overlying the Ordovician target layer is very significant, and it has seriously affected the normal drilling and wellbore stability. In this study, taking the Silurian of the No. A Strike-slip Fault Zone in the Shunbei area as an example, the development characteristics of strike-slip faults and fractures, the strength of the in-situ stress field, and the influence of these factors on the drilling mud leakage were systematically studied using 3D seismic, logging, drilling, logging, well log, and engineering construction data. The results show that the mud leakage in strata S1t is significantly larger than that in S1k, and the leakage amount in sandy mudstone is the largest; the strong strike-slip extension developed the negative flower-shaped normal faults and the right-order swan-type faults and caused serious stratigraphic fragmentation. The amount of mud leakage increases with the increase of fault distance. Moreover, the closer to the fault, the higher the frequency and amount of mud leakage. When the distance between the wellbore and the fault exceeds 300 m, the possibility of mud leakage decreases significantly. The Silurian S1t is dominated by high-angle and vertical tension-shear fractures with good opening; while the S1k is dominated by low-angle structural and horizontal bedding fractures. The differences in fracture type cause the mud leakage in S1t to be significantly larger than that of S1k. In addition, the fracture development intervals identified by the R/S-FD method are in good agreement with the mud leakage intervals, which further indicates that the degree of fracture development is the key factor leading to the drilling mud leakage. The study also found that the degree of fracture development and the difference in horizontal principal stresses are the dominant factors leading to high Silurian mud leakage.

Numerical simulation of in-situ stress field characteristics about the dam site area of Baihetan Hydropower Station

In order to study the geological history of the rock mass in the Baihetan dam site area, this paper carries out a numerical simulation study on the in-situ stress field in the dam site area of Baihetan Hydropower Station. With the help of numerical simulation technology, the macro distribution law of the in-situ stress field is discussed. The results show that the in-situ stress value in the dam site area belongs to medium ∼ high stress level. The large principal stress value of the powerhouse on the left and right bank will be close to or even greater than 25 MPa, furthermore the stress state are not good. The horizontal large principal stress is close to the horizontal small principal stress. The results of the paper reproduce the load action history of the rock mass in the dam site area, which provides a preventive theory for the safety of the dam construction of Baihetan Hydropower Station.

A New Method of Quantitatively Evaluating Fracability of Tight Sandstone Reservoirs Using Geomechanics Characteristics and In Situ Stress Field

This paper studied the fracability of tight sandstone reservoirs by means of incorporating geomechanics properties and surrounding in situ stresses into a new model. The new fracability evaluation model consists of variables such as brittleness index, critical strain energy release rate index, horizontal stress difference, and minimum horizontal principal stress gradient. The probability of interconnection of a complex fracture network was quantitatively studied by the brittleness index and horizontal principal stress difference index. The probability of obtaining a large stimulated reservoir volume was evaluated by the critical strain energy release rate index and minimum horizontal principal stress gradient which also quantifies conductivity. This model is more capable of evaluating fracability, i.e., it agrees better with the history of production with a high precision and had correlation coefficients (R2) of 0.970 and 0.910 with liquid production of post-fracturing well testing and the average production of six months of post-fracturing, respectively. It is convenient that all model inputs were obtained by means of loggings. Using this model, tight sandstone reservoirs were classified into three groups according to fracability: Frac ≥ 0.3 MPa−1·m for Type-I, 0.22 MPa−1·m ≤ Frac < 0.3 MPa−1·m for Type-II, and Frac < 0.22 MPa−1·m for Type-III.