Fracture Height Research Articles

Characteristic Developments of the Water-Conducting Fracture Zones in Weakly Cemented Overlying Strata of Jurassic Coal Mines in Western China

The overlying weakly cemented, and poorly performing strata in Jurassic mines of western China have mechanical properties that are generally lower than those in the Carboniferous-Permian coal mines of central and east China. During coal mining, the overlying strata easily deform and fracture. These then formed water-conducting channels, triggering a series of eco-environmental issues, including ground fracturing, collapsed surfaces, declined underground water levels, deserted lands, and even severe water/sand burst accidents. To study the fracture characteristics of weakly cemented overlying strata and the evolution law of water-conducting fractures in Jurassic coal mines in western China, this study selected Tashidian Erjingtian Mine in Korla, Xinjiang, as the research object. Based on the simulation data obtained with physical analog model testing and field monitoring results, the authors investigated the development of water-conducting fractures in the weakly cemented overlying strata during the coal seam mining process. We simultaneously determined the location of key strata in the working face based on key stratum theory. According to the present research results, key strata controlled the development height of water-conducting fractures. When the primary key stratum or sub-key stratum was not fractured, the development of water-conducting fractures was stagnant; water-conducting fractures developed abruptly when the primary key stratum or sub-key stratum was cracked. The heights of water-conducting fractures in the weakly cemented overlying strata of western China exceeded that of similar stopes of central and east China. These research results provided theoretical and technical support for safety in production at Tashidian Coal Mine. In addition, they offered a reference for green and safe production in Jurassic coal mines of western China.

Laboratory evaluation on oil-soluble resin as selective water shut-off agent in water control fracturing for low-permeability hydrocarbon reservoirs with bottom aquifer

During the development of low-permeability hydrocarbon reservoirs with bottom aquifer, hydraulic fracturing is essentially employed for commercial oil flow while increasing the potential risk of serious water production, thus water control hydraulic fracturing technology plays important role on addressing this challenge. In this work, a water control fracturing technique is developed to integrate fracture height containment with selective water shut-off. Specifically, oil-soluble resin is used as selective water shut-off agent and is injected with sinking agent simultaneously, carried by fracturing fluid at the fracture generation stage, to establish an improved artificial barrier. Afterwards, a modified fracture conductivity test equipment is designed and manufactured to measure the selective conductivity of the artificial barrier, its sensitivity to temperature, ratio of oil-soluble resin to sinking agent, two-phase flow are studied to evaluate the capability of selective water shut-off.The results demonstrated that 1) the occupation in porous space of sinking agent (0.212–0.425 mm) and the status change from glassy state to high elastic state of oil-soluble resin are mainly responsible for water shut-off; 2) The ratio of oil-soluble resin to sinking agent in 10 g: 70 g and temperature at 75 °C are two critical value to significantly reduce water conductivity in our experiments; 3) Fast dissolution of resin in oil results in oil conductivity over 5 to 100 times higher than water conductivity to achieve selective water shut-off. The results presented herein will provide important guidance on water control in low permeability reservoirs with active bottom aquifer and will promote the unconventional hydrocarbon recovery.

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.

Simulation and experimental comparison study based on predicting forming limit curve of SUS304 sheet material

In this study, the modified maximum force criterion was used to ensure an accurate determination of the forming limit curve (FLC) for the SUS304 sheet metal. At first, the stress–strain curves according to Voce and Swift hardening models were verified using the experimental data and the stress function deduced by Hill in 1984 to predict FLCs. The accuracy of the FLCs was evaluated by analyzing the equivalent fracture strain data at three distinct locations: Biaxial tensile strain (BT, [Formula: see text]), uniaxial tensile strain (UT, [Formula: see text]), and plane strain (PS, [Formula: see text]), and then comparing them with the corresponding linear FLC experimental data. The accuracy of the predicted FLCs was further tested by comparing the fracture height of the samples according to the Nakazima model in the FEM simulation and the corresponding experiments.

Two-dimensional models for waterflooding induced hydraulic fracture accounting for the poroelastic effects on a reservoir scale

This work focuses on the developing of a computationally efficient numerical model for a waterflooding induced planar hydraulic fracture in a poroelastic medium. In particular, under certain assumptions it is possible to decouple the fully coupled model into poroelastic reservoir and purely elastic fracture subproblems. Further, the general 3D problem formulation for a planar fracture is reduced to two dimensions for early time plane strain fracture and late time constant height fracture. Noticeably, the division of the problem into two subproblems allows us to use the displacement discontinuity approach for the fracture related part, and finite element method for the reservoir related part. The latter is especially important for the constant height fracture, which cannot be modeled using exclusively the finite element approach in two dimensions. The algorithm is benchmarked against the available analytical solutions, as well as compared to other numerical codes. The developed numerical method is used to study the influence of the heterogeneous pore pressure and the corresponding stress for different waterflooding fracturing situations. We consider the cases with both injection and production wells operating nearby. With the presence of such wells, the fracture growth becomes asymmetrical and both the well type and location are important. The qualitatively different fracture behavior is observed for various cases. Other numerical examples include the simulation of a step-rate test as well as investigation of the possibility of fracture control by altering the injection rate.

Numerical Simulation of Gas-Liquid Gravity Displacement in Vertical Fractures during Drilling of Carbonate Formations.

In petroleum drilling, carbonate formations characterized by natural fractures can result in troublesome gas-liquid gravity displacement, which refers to the phenomenon that the drilling mud leakage and gas kick are simultaneously triggered. This work focuses on clarifying the mechanism of gas-liquid displacement in vertical fractures during the drilling of carbonate formations and investigating the characteristics of gas-liquid displacement under various conditions. First, the bottom hole pressure allowing for gas-liquid gravity displacement is analyzed, which determines the coexistence condition of leakage and kick in vertical fractures. Then, a theoretical model of gas-liquid displacement flow in a vertical fracture is established. To verify the reliability and accuracy of the model, the results of numerical simulation are compared with those of a visualization experiment. The development process and flow characteristics of gas-liquid displacement in the fracture under different conditions are numerically simulated. The effects of pressure difference, drilling mud property, and fracture geometry on the gas-liquid displacement rate are analyzed. It is found that the drilling mud leakage rate increases with the increase of fracture width, fracture height, and drilling mud density, while it decreases with the increase of pressure difference and fracture length. The gas invasion rate increases with the increase of fracture width, fracture height, and pressure difference, while it decreases with the increase of drilling mud density and fracture length. The equations for leakage rate and gas invasion rate are derived by the response surface method, and the methods for mitigating gas-liquid gravity displacement are discussed. It is expected that the present work provides a better understanding of the gas-liquid gravity displacement in carbonate formations.

Influence of thermo-mechanical aging on fracture resistance and wear of digitally standardized chairside computer-aided-designed/computer-assisted-manufactured restorations

ObjectivesTo investigate the influence of thermal cycling and mechanical loading (TCML) aging on fracture resistance and wear behavior of various chairside computer-aided-designed/computer-assisted-manufactured (CAD/CAM) premolar crowns cemented on standardized tooth abutments. MethodsEighty chairside CAD/CAM crowns were prepared using lithium disilicate (IPS e.max CAD; EM), zirconia-infiltrated lithium silicate (Celtra Duo; CD), polymer-infiltrated ceramic network (Vita Enamic; VE), and resin nanoceramics (Cerasmart; CS) (n = 20). The specimens were divided into two groups (n = 10). In one group, they were subjected to TCML: thermocycling (6000 cycles in distilled water at 5–55 °C) and mechanical loading (50 N for 1.2 × 106 cycles), while in control group they were stored in distilled water (37 °C for 24 h). The fracture load, height loss, and volume wear of the crowns were measured after TCML. Fractography was performed on fractured specimens. Data were analyzed using analysis of variance and multiple comparison tests (α=0.05). ResultsThe mean fracture loads of EM and CD were significantly higher than those of EC and CS (p<0.05). There was no significant change in the fracture load of any CAD/CAM crowns after TCML (p>0.05). CS exhibited a significantly higher volume wear than the other materials investigated. The wear tracts of all TCML crowns acted as failure origins during the fracture test. ConclusionsThe fracture resistance of glass-ceramic CAD/CAM crowns was significantly higher than that of resin composite crowns. A 5-year TCML aging did not affect the fracture resistance of CAD/CAM crowns investigated. However, TCML treatment produces a larger wear track in CS than in other materials. Clinical SignificanceAppropriate chairside CAD/CAM restorative material should be selected for successful clinical practice after considering the fracture and wear resistance of the crowns.

Microstructure and Properties of High Frequency Pulse MAG Butt Welded Joints of S355 Steel with Different Diameters

In this paper, the diameter of 1.2mm and 1.6mm welding wires were used to carry out high-frequency pulse MAG butt welding process test on S355J2W+N weathering steel. The analysis of the microstructure characteristics of the welded joints under the two working conditions shows that there is little difference and both are ideal. There were more acculate ferrite (AF), less pearlite (P) and bainite (BG), and no larger Weisserite structure and less ferrite side-plate (FSP) structure. The weld is well formed, weld defects such as gas pores and cracks are not found. The impact test showed that the impact energy Akv (-40 °C) of the welded joint at -40 °C was higher than the specified minimum impact energy of 27 J. Compared with the 1.2mm welding wire, the impact energy of the 1.6mm welding wire is lower. Tensile test results show that the fracture occurs at the base metal position. and the fracture height is uneven, forming an angle of 45° with the tensile stress direction, which is a ductile fracture. When the bending angle of the butt joint samples reaches 180°, no cracks are both found on the tensile surface, and the plastic index of the welded joint samples is qualified and has good bending performance.

Numerical Simulation Research on the Effect of Artificial Barrier Properties on Fracture Height

Hydraulic fracturing is an important measurement for the stimulation of oil and gas wells and is widely used in the development of low-permeability and ultra-low-permeability reservoirs. However, fractures can pass through barriers with poor properties during fracturing, resulting in fractures that do not reach the pre-designed length. In a worse situation, it is possible to communicate with the water layer and cause sudden water flooding, resulting in the failure of the fracturing construction. In order to improve the efficiency of fracturing construction, an effective way to control the height of fractures is by laying diverting agents to form artificial barriers. In this study, we established a three-dimensional numerical calculation model of fracture propagation, considering artificial barriers in the finite element analysis framework; the fracture propagation is governed by a cohesive zone model. The influence of artificial barriers with different Young’s modulus and different permeability on the fracture height was simulated and calculated. Different fracture geometries under different pumping injection rates were also considered. The simulation results show that the smaller the Young’s modulus of the artificial barrier, the smaller the extension in the direction of the fracture height: when its Young’s modulus is 28 GPa, the half fracture height is about 25 m, while when Young’s modulus increases to 36 GPa, the half fracture height increases by about 10m. When the fracture does not penetrate the artificial barrier area, the larger the Young’s modulus, the smaller the fracture width and the larger the fracture height. With the change in the permeability of the artificial barrier, the change in the fracture width direction of the fracturing fracture is only about 0.5 m, but the inhibition on the fracture height direction is more obvious; in the case of maximum permeability and minimum permeability, the fracture height change is 10 m. The influence of pumping injection rates on the width and height of the fracture is obvious: with the increase in the pumping rates, both the height and width of the fractures increase. However, when the pumping rate increases from 0.12 m3/s to 0.14 m3/s, the change in the direction of fracture height is no longer significant, and the increase is only 0.6 m. This study investigates the role of artificial barrier properties and pumping rates in controlling fracture height extension, clarifies the feasibility of artificial barriers to control fracture height technology, and provides guidance for the selection of diverting agents and the determination of the pumping rate in the process of fracturing construction.

Fracturing criterion of rock hydrofracturing considering pore pressure effect

Traditional hydraulic fracturing theory believes that as the initial pore pressure increases, the breakdown pressure of the rock will decrease. Previous experimental studies have shown that the breakdown pressure of rock hydraulic fracturing may increase with the increase of initial pore pressure (gradient), which cannot be explained by traditional theory. The current understanding of the effect of pore pressure and its gradient during hydraulic fracturing is still unclear. In this study, the pore pressure effect of rock hydraulic fracturing is analyzed based on a large number of macroscopic and microscopic phenomena of rock hydraulic fracturing in the previous study. Then, a new fracture criterion of rock fracturing is built considering the pressure-gradient effect. This new fracture criterion can reflect the main influence factors, including the rock particle size, porosity, pumping flow, inner diameter of open hole section, length of main fracture, height of main fracture (or length of open hole section), fluid viscosity, pore pressure, minimum initial in situ stress and rock tensile strength. The new fracture criterion is examined by the rock fracturing experiment which considering the pressure-gradient effect. The results show that the proposed fracture criterion considering the pore pressure effect can well predict the breakdown pressure of rock, and the prediction trend is consistent with the experimental results. The average error is less than 1% when adopting the present fracture criterion. The parameter sensitivity of the fracture criterion is analyzed. Results show that the fracture pressure increases with the rock porosity and this trend becomes more apparent with a larger initial pore pressure. It shows that the fracture pressure increases with the pumped flow rate. Besides, it shows that the fracture pressure decreases when increasing the particle size of the rock, but the decreasing trend gradually slows down. The research results can provide a theoretical basis for the mechanism of rock hydraulic fracturing and the structural modification effect of fluids in rock engineering.

Three dimensional multi fracture induced stress model for highly deviated wells

ABSTRACT At present, the development of some oil and gas fields has gradually shifted from vertical to highly deviated wells. To improve the intensity of reservoir reconstruction, highly deviated wells mostly adopt staged fracturing for reservoir reconstruction. The fracture interference law of multiple fractures in highly deviated wells is not clear, and the fracture steering and stress interference problems in the fracturing process are obviously different from those in horizontal wells, resulting in a lack of a theoretical basis for fracture spacing design. Therefore, it is necessary to study the stresses induced by multiple fractures in highly deviated wells. To reproduce the spatial distribution of multiple fractures in highly deviated wells and analyze the changes in induced stress more accurately, a three-dimensional numerical model of the fracture-induced stress field in highly deviated wells was established based on the finite element method and elasticity theory, which can simulate a fracture-induced stress field under different angles of inclination. The results indicate that the key to mutual exclusion or proximity of the two fractures is whether the fractures overlap in the plane parallel to the fracture height direction. Based on the analysis of the control variables, the first fracturing fracture height is the key factor affecting the induced stress, and the fracturing fracture height has slight effect on the induced stress. As the angle of inclination increases, the probability of the two fractures overlapping in space increases and the critical distance from the induced tensile stress to the induced tensile stress decreases. The influence of the fracture half-length, net pressure, and stress difference on the induced stress is related to whether the spatial projection of the two fractures overlaps. The research results provide a theoretical basis for the optimal design of staged fracturing in highly deviated wells.

Anisortopic Modeling of Hydraulic Fractures Height Growth in the Anadarko Basin

Correct estimation of hydraulic fracture height growth is a critical step in the design of Hydraulic Fracturing (HF) treatment, as it maximizes the reservoir stimulation and returns on investment. The height of the fractures is governed by several in situ conditions, especially stress variation with depth. The common workflow to estimate stress is by building the mechanical earth model (MEM) and calibrating it using the Diagnostic Fracture Injection Test (DFIT). However, DFIT interpretation is a complex task, and depending on the method used, different results may be obtained that will consequently affect the predicted hydraulic fracture height. This work used the tangent and compliance methods for DFIT interpretation, along with isotropic and anisotropic stress profiles, to estimate the HF height growth using numerical modeling in a 3D planar HF simulator. Data from two wells in the Anadarko Basin were used in this study. The predicted height was compared with microseismic data. The results showed that even though the tangent method fits better to the isotropic stress profile, HF did not match with the microseismic data. On the contrary, the anisotropic stress profile showed a good match between the compliance DFIT model and the microseismic events. Based on the discussions presented in this study, the validity of the DFIT interpretation is debatable, and when the formations are anisotropic, the isotropic model fails to correctly estimate the minimum stress profile, which is the main input for the estimation of the fracture height. This is in addition to the fact that some researchers have questioned the use of the tangent method in low-permeability formations.

In situ stress variation and coal reservoir permeability response of the Jurassic Yan'an formation in the southwestern Ordos basin, China: Its impact on coalbed methane development

The in situ stress (ISS) and permeability determine the coalbed methane (CBM) development method and extraction efficiency to a certain extent. Based on the data of the CBM well test and microseismic monitoring in the Jurassic Yan'an Formation, a prediction model of the ISS is established, and its influence on permeability and CBM development in the southwestern Ordos Basin, China, is discussed. The results show that the orientations of maximum principal stresses (Shmax) in the study area's eastern, central, and western parts are NE–SW, SEE–NWW, and NNW–SSE, respectively. With the increased burial depth, the main ISS parameters show an S-shaped variation. The study area's ISS state can be divided into Shmax > vertical stress (Sv) > horizontal minimum principal stress (Shmin) (<420 m), Sv > Shmax > Shmin (420 m–800 m), and Shmax ≈ Sv > Shmin (>800 m), and the transformation depth of the ISS field is 550 m and 1000 m. The lateral pressure coefficients (λ) ranged from 0.30 to 1.19, with an average of 0.69. The λ, Shmax/Shmin and Shmin/Sυ of the stress field are small, which indicates that the horizontal tectonic stress is weak. The coal reservoir's permeability is distributed between 0.0084 and 6.84 mD (av. 1.13 mD). Affected by the variation of the ISS state in the vertical direction, the coal reservoir permeability shows obvious zoning. The tensile stress field is beneficial to high-permeability coal reservoir formation, but it is constrained by the coupling constraints of a coal reservoir's confining pressure and effective stress. The coal reservoirs are in a normal fault stress state, which is beneficial for improving their hydraulic fracturing effect. Since the Shmin in the study area is always smaller than the Sυ, the height of the fracturing fracture should be controlled in the fracturing of the coal reservoir to avoid the overlying aquifer being connected by fracturing fractures. The above new insights have important guiding significance for the hyperpermeability CBM reservoir prediction, well-bore structure and hydraulic fracturing design in the Ordos Basin.

Numerical Simulation and Sensitivity Analysis of Hydraulic Fracturing in Multilayered Thin Tight Sandstone Gas Reservoir

Hydraulic fracturing is a necessary measurement to realize the commercial exploitation of oil and gas, but its application in multilayered thin tight sandstone gas reservoirs is still not perfect, which usually have thin gas layers mixed with complex intervals, and shows a dramatic variation in geological and geomechanical properties in the vertical direction. When conventional hydraulic fracturing methods are applied to this kind of reservoir, it is hard to get proper fracture propagation, especially for fracture height control. Facing this situation, this paper proposes a numerical study of the hydraulic fracturing mechanism and analyzes its influencing factors in the multilayered thin tight sandstone gas reservoir. Relying on a real reservoir in the Ordos Basin in China, relevant geological and geomechanical parameters of major gas layers and interlayers are obtained. According to these parameters, the hydraulic fracturing simulation in the multilayered thin tight gas reservoir model is carried out, based on which, the sensitivity analysis of different geological and fracturing parameters which affect the fracture propagation is performed. Furthermore, a real low-production well after fracturing in this kind of reservoir is selected as an example, and based on the analysis, an optimized fracturing scheme is proposed to adapt to the characteristics of the reservoir. According to the comparison of fracturing and production simulations, the optimized fracturing scheme can prevent hydraulic fractures from breaking through thin interlayers, control the fracture height, and prevent fractures from communicating strata with a high water-bearing layer. At the same time, with the same amount of proppant and fracturing fluid, longer fracture length and better fracture conductivity are created, so that the productivity of the optimized fracture has been greatly improved.

Laboratory study of the factors affecting hydraulic fracturing effect for inter-salt oil shale layers, Qianjiang Depression, China

This study aims to investigate the potential factors affecting hydraulic fracturing of inter-salt oil shale reservoirs in the Qianjiang Depression, China. Using the inter-salt shale samples, the re-crystallization seepage tests, rock mechanical tests under high temperature and pressure, salt rock creep tests, and direct shear tests were conducted. The testing results suggest several major factors that affect hydraulic fracturing effects in the end. First, the seepage of reservoir and fracturing fluid through hydraulic fractures leads to salt dissolution and crystallization, reducing the effective seepage area of fractures. Second, the salt crystal may block the pore throats or micro fractures after brine invades the shale, decreasing the overall permeability. Third, the low strength and obvious plasticity of inter-salt shale and the strong creep characteristics of salt rock raise difficulties for proppant to effectively support fracture walls, thereby sharply narrowing the hydraulic fracture width. Lastly, the weak interfaces (bedding planes and lithology interfaces) in inter-salt oil shale reservoirs restrict the height of hydraulic fractures, resulting in the disconnection of seepage channels between multiple inter-salt shale reservoirs. Thus, several factors together reduce reservoir permeability, weaken the fluid flow capacity in the fracture, narrow the fracture width, and limit the effective stimulation volume, resulting in weaken the effect hydraulic fracturing.

Optimization of volume fracturing technology for shallow bow horizontal well in a tight sandstone oil reservoir

The physical property of Chang 6 reservoir in Yanchang oilfield is poor, and the heterogeneity is strong. Multistage fracturing of horizontal wells is easy to form only one large horizontal fracture, but it is difficult to control the fracture height and length. The new mining method of “bow horizontal well + multistage horizontal joint” can effectively increase the multistage horizontal joint’s spatial position, which improves the drainage area and stimulation efficiency of oil wells. Due to the reservoir’s low permeability and strong heterogeneity, the single well mode of “bow horizontal well + multistage horizontal fracture” cannot effectively produce Chang 6 reservoir. To improve the production degree of the g 6 reservoir, the fracture model is established using equivalent conductivity and the multigrid method. The pressure response functions of horizontal wells and volume fracturing horizontal wells are established by using the source function, and the relationship between reservoir permeability and starting pressure gradient in the block is calculated. On this basis, the reservoir productivity equation of the block is established, which provides a basis for optimizing the fracturing design parameters of horizontal wells. It is proposed that the flow unit should be considered in the design of fracturing parameters of horizontal fractures, the number of fractures should comprehensively consider whether the fractures can make each flow unit be used, and have large controlled reserves, and the scale of fracturing should comprehensively consider the output and cost. The fracture network model is established by using equivalent conductivity and multi-gridthod, and the volume fracturing design parameters of horizontal wells are optimized, considering the seepage characteristics of the flow unit. The fracturing design parameters of the horizontal section are further defined, which provides a theoretical basis for the efficient development of shallow tight reservoirs.

DDR4 Ball Grid Array Package Intermittent Fracture Effect on Signal Integrity

DDR4 die are commonly packaged in Ball Grid Array packages. The package solder balls develop fractures due to difference in the thermal co-efficient of expansion of the package and printed circuit board. The intermittent behavior of the fracture is due to the momentarily opening of the solder joint due to vibration or the warpage of the package and the printed circuit board. This intermittent behavior can result in no fault found phenomenon in memory systems. DDR4 response in the presence of an intermittent fracture depends on the location of defect. The defect can occur in clock, address or data channel. A test fixture is used to show the AC coupling nature of fracture in ball grid array package solder ball. The intermittent change in the height of fracture is analyzed using 3-D electromagnetic model of the solder ball using high frequency structure simulator (HFSS) software. HFSS model of the fractured solder ball is used along with DDR4 channel topology to compare the sensitivity of clock, address and data channel response to intermittent fracture. It is shown that the data channel is most sensitive to intermittent fracture. DDR4 data mask violation occurs for even a small fracture height of 0.1 μm. For clock channel, the eye degrades or becomes smaller as the fracture height increases from 0.1 μm to 3 μm. But even for 3 μm fracture height, clock eye diagram remains within DDR4 clock +/- 110 mV specification. For address channel the eye degrades or becomes smaller when the height of fracture increases from 0.1 μm to 3 μm. For fracture height of 3 μm, DDR4 address +/- 65 mV input specification violation occurs. Address channel is more sensitive to intermittent fracture as compared to clock channel. The analysis shows that there is always intermittent error in data channel due to intermittent fracture and there are more intermittent errors in address channel compared to clock channel.

APPLICATION STUDY OF TEMPORARY PLUGGING ASSISTED FRACTURING IN TRANSITION ZONES OF SABEI OILFIELD

The northern oil and water transition zone of the Sabei Oilfield is the largest development area of the whole Daqing Changyuan transition zone. At present, it is producing with ultra-high water cut, and both water flooding and polymer flooding are under operation. In order to clarify the distribution characteristics and existing state of the remaining oil in the transitional zone, liquid nitrogen freezing and ultraviolet fluorescence microscopy are used to quantitatively characterize the microscopic occurrence of residual oil in cores after different volumes of water flooding, the relationship between water flooding intensity and microscopic residual oil distribution in free state and immobile state is established. Analysis results of residual oil in SII layer of the Sabei Oilfield show more immobile residual oil. Conventional fracturing measures have been done to improve oil recovery, but its efficiency deteriorated year by year, which is only 51.1&amp;#37; of the measures done for the oil-rich zones. Therefore, temporary plugging assisted fracturing technology using fiber was carried out to improve the stimulation efficiency in the transition zone. Also, an improved permeability calculation model was established to analyze the influence of the fracture length, fracture height, and oil viscosity on productivity ratio and recovery factor. Based on these results, the optimal value ranges of operational parameters were obtained. Then, eight wells were stimulated using the temporary plugging assisted fracturing technology in the field. The results show that after fracturing the average daily oil production rate increased by 6.3 t and the cumulative oil production from eight wells increased by 17386 t in 720 days, demonstrating the efficacy of the temporary plugging assisted fracturing technology compared with conventional fracturing.

Research on Development Mechanism and Criterion of Upward Fractures in Longwall Face Mining

After mining, upward fractures develop from bottom to top, and they are key channel for groundwater and gas flow and also sand burst; therefore, it is important to study the development mechanism and criterion of upward fractures. Combining with physical simulation and theoretical analysis, the development law of mining‐induced upward fractures was revealed, and the mechanism and criterion of fracture propagation was studied. The results show that the development of mining‐induced upward fractures can be divided into the following three stages: with the face advances from the open cut, the vertical fractures are generated at the mining boundary, and the roof is flexural but not caved; it is “Fractures generate stage.” After roof caves, the upward fractures extend and develop upward along the caving angle with continue advances; it is “Fractures develop and extend stage.” When the face reaches critical mining, the development height of the upward fractures is at its maximum and is basically invariable; it is “Fractures stabilization stage.” Mining‐induced fractures can be analyzed as mixed‐type fractures in fracture mechanics; when the combined stress exceeds the critical strength of stratum, it will extend downward until penetrate through the stratum, and the upward fracture develops and extends upwards. The parameter controlling the fracture of the rock stratum is the maximum hoop tensile stress σ(θ)max, at the fracture end, the theoretical model of fracture propagation was established, and the criterion of upward fractures was proposed.

Study on the Law of Hydraulic Fracture Propagation in Low Permeability Thin Interbed Reservoir

The third member of Weixinnanliu in the west of the South China Sea develops thin interbeds, and the vertical extension of fracturing fractures is excessive. Once the fractures extend vertically to the upper and lower aquifers, it is easy to cause water flooding of oil wells, and the effect after fracturing is not obvious. The present work aims to explore the longitudinal extension law of fractures in Low Permeability Thin Interbed Reservoir based on the finite element calculation platform. A three-dimensional expansion model of hydraulic fractures in the target reservoir was established, and the displacement, fracturing fluid viscosity, minimum horizontal principal stress difference, vertical stress, interlayer thickness, perforation point separation were studied. The interlayer distance and other factors affect the crack propagation law. The research results show that the thin interbed fractures have three forms: T-shaped fractures, through-layer fractures, and I-shaped fractures; for the target layer, the overlying stress is relatively large, and the minimum principal stress is along the horizontal direction. Vertical cracks; the farther the perforation point is or the greater the stress difference, the smaller the thickness of the interlayer required to control the fracture height; the stress difference is 3 MPa, and the distance between the perforation points exceeds 10 m, the thickness of the interlayer is required to be ≥4 m; In order to ensure that the width of the fracture in the middle spacer does not affect the placement of the proppant, it is recommended that the displacement be controlled within 3 m3/min and the viscosity of the fracturing fluid is 150 mPa·s; in addition, the thickness of the spacer required to control the fracture height is different due to different geological parameters. Different, different wells need targeted analysis.