Fracture Breakdown Pressure Research Articles

Shale oil recovery by CO2 injection in Jiyang Depression, Bohai Bay Basin, East China

Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO2 injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO2 injection, and the influences of CO2 pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO2 pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO2 pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO2 puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the “injection + soaking” stage, the exploitation degree of heavy hydrocarbons is enhanced by CO2 through its effects of solubility-diffusion and mass-transfer. In the “huff” stage, crude oil in large pores is displaced by CO2 to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO2 pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO2 is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO2 pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO2 huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO2 pre-pad fracturing, the formation energy replenished effectively after CO2 huff-n-puff in a single well, and the well productivity improved.

Impact of Wellbore Cross-Sectional Elongation on the Hydraulic Fracturing Breakdown Pressure and Fracture Initiation Direction

Investigation of breakdown pressure in wellbores in complex conditions is of great importance, both in fracture design and in wellbore log interpretation for in situ stress estimation. In this research, using a two-dimensional numerical model, the breakdown pressure is determined in ellipsoidal and breakout wellbores. To find the breakdown pressure, the mixed criterion is used, in which the toughness and the tensile strength criteria must be satisfied concurrently. In breakout boreholes, the breakdown pressure is lower than the circular wellbores; indeed, the ratio of the breakdown pressure of the breakout wellbore to the breakdown pressure in the circular wellbore is between 1 and 0.04, depending on the deviatoric stress and the width and depth of the breakout zone. In breakout wellbores, the fracture initiation position depends on the deviatoric stress. In small deviatoric stresses, the fracture initiation position is aligned with the minimum in situ stress, unlike circular boreholes; and in large deviatoric stresses, the fracture initiates in the direction of the major principal stress. In large wellbores, the breakdown pressure is controlled by the tensile strength of the rock; and in small wellbores, the breakdown pressure is under the control of the energy spent to create new crack surfaces.

Simulation of fracture propagation law in fractured shale gas reservoirs under temporary plugging and diversion fracturing

Natural fractures (NFs) are developed in shale gas reservoirs, which can easily cause frac hits during hydraulic fracturing and reduce the productivity of infill wells and parent wells. Temporary plugging diverting fracturing (TPDF) can hinder the single forward extension of fracture transition and avoid the communication of hydraulic fractures (HFs) or NFs adjacent to wells. In order to explore the fracture propagation law of TPDF in fractured shale gas reservoirs, this study systematically evaluates the main factors such as stress difference, displacement, and fracturing fluid viscosity on the fracture temporary plugging diversion (TPD) law by means of true triaxial hydraulic fracturing simulation device and cohesive element model in ABAQUS. The findings reveal that (1) the law of fracture initiation and propagation at the engineering scale is similar to that in indoor experiments. Upon the primary fracturing (PF), the smaller the horizontal stress difference, the larger the pumping displacement, and the smaller the viscosity of the fracturing fluid is, the greater the corresponding fracture breakdown pressure and the stronger the rock compression resistance. (2) After TPD secondary fracturing, a small horizontal stress difference and a large pumping displacement facilitate the formation of a vertical complex fracture network structure on the primary fracture. Because of the small size of the indoor rock, viscosity has little effect on the fracture propagation of the TPDF, but the numerical simulation results reveal that the higher the viscosity, the greater the width of the new fracture. In addition, (3) the smaller the angle between the new fracture opened after PF and TPDF, the better the propagation effect of the new fracture. Meanwhile, the farther the temporary plugging zone is from the fracture front end, the wider the new fracture opened after TPDF. The field construction results reveal that the TPDF technology can avoid the effect of HFs, thus preventing frac hits during shale gas reservoir reconstruction. This study not only posits a physical and numerical simulation method for simulating the fracture propagation law of TPDF in fractured shale gas reservoirs but also provides theoretical guidance for applying TPDF to field construction.

Backstress Influence on the Formation Stress Field in Hydraulic Fracturing Experiments

This work presents an analysis of data obtained through unique laboratory experiments on hydraulic fracturing. In the experiments, sufficiently large artificial samples were used to model a reservoir. Thus, it was possible to simulate several wells simultaneously, given that hydraulic fracture was initiated in one of them. In addition, the setup construction provided a true triaxial stress–strain state. The setup allowed us to investigate parameters that are difficult to access in real conditions. The data processing based on six laboratory experiments on hydraulic fracturing showed discrepancies between the values of the minimum stresses calculated from the fracture closure pressure and the actual values known based on the experimental conditions. There was also a discrepancy between the theoretical values of the fracture breakdown pressure and those obtained through the experiments. This paper examines phenomena such as backstress as the main reasons for this discrepancy. Backstress is stress acting on the walls of a fracture or well and is caused by the filtered hydraulic fracturing fluid. The authors demonstrated that by taking into account this phenomenon, one can significantly reduce the differences between calculated and experimental values. Therefore, the authors call for the careful use of the standard theory when determining the stress state in real fields.

Grain-scale analysis of fracture paths from high-cycle hydraulic fatigue experiments in granites and sandstone

Previous studies have revealed that hydraulic fracturing behavior in crystalline rock (e.g., granite) is highly dependent on mineral content, grain size, and heterogeneity and is therefore quite different from the behavior observed in sedimentary rock (e.g., sandstone). We investigated hydraulic fracture paths generated via cyclic and monotonic injection in Pocheon granite, Gonghe granite, and gray sandstone. The gray sandstone has a porosity of 9.0% and its anisotropy was not considered in this study. The effect of cyclic injection on the reduction of hydraulic fracturing breakdown pressure was more significant in the two granites compared with that in the sandstone. Computed tomography images were obtained on fractured specimens for a quantitative evaluation of hydraulic fractures that included fracture length, fracture aperture, and tortuosity. Minerals along hydraulic fractures in the two granites were identified via an analysis of thin section collages from microscopic observations. We analyzed the role of different minerals (i.e., quartz and biotite) and pre-existing defects – such as microcracks and natural fractures – in controlling hydraulic fracture propagation in monotonic and cyclic injections.

Effects of hydrostatic pressure on hydraulic fracturing properties of shale using X-ray computed tomography and acoustic emission

The study of the hydraulic fracturing characteristics in shale reservoirs is crucial for improving the permeability of shale gas reservoirs. In this study, hydraulic fracturing tests are conducted on full-diameter shale cores, and the hydraulic fracturing characteristics of shale with different bedding angles under high hydrostatic pressure are studied. The results show that under a hydrostatic pressure of 59 MPa, the shale sample will rupture twice in the breakdown stage during hydraulic fracturing. When the bedding inclination increases from 0° to 90°, the shale fracture breakdown pressure first decreases and then increases, showing an overall downward trend. Under high hydrostatic pressure, shale specimen surface fracture morphology and X-ray computed tomography reveal that a bedding angle close to 45° is more conducive to forming a complex hydraulic fracture network, which makes the fractal dimension of the fracture network larger. The bedding plane of shale is the direct cause of the diverse propagation patterns of hydraulic fractures. The b-value is a parameter that characterizes the magnitude–frequency relationship of an earthquake, and it is closely related to the rock rupture process. The b-value varies with different trends with the expansion of hydraulic fractures, but they all reach the lowest point before the failure of the shale sample. The higher the hydraulic fracture network complexity, the lower the peak b-value is. This work provides a qualitative understanding and scientific explanation of the hydraulic fracturing characteristics of anisotropic shale under hydrostatic pressure.

A Numerical Study of Hydraulic Fracture Propagation Geometry in a Layered Shale Reservoir

An unconventional shale reservoir commonly develops multiple layers and shows strong anisotropy in mechanical properties, which has a great effect on hydraulic fracture propagation geometry. The most common mechanical properties are elastic modulus, Poisson’s ratio, tensile strength, and formation permeability. Therefore, the extended finite element method- (XFEM-) based cohesive zone model (CZM) is applied to analyze the effect of these mechanical properties on both the fracture propagation geometry and breakdown pressure in a layered shale reservoir after verifying the present numerical method by published analytical results. The parametric analysis indicates that the stiff or soft outer layers limit the fracture propagation width, while promoting the fracture propagation length. Higher Poisson’s ratio and formation permeability in outer layers narrow the fracture propagation width in middle layer. Poisson’s ratio contrast between different layers almost has no significant effect on the fracture propagation length and breakdown pressure. The hydraulic fracture propagation geometry presents the trend of “shorter and wider” with the increase of the tensile strength in outer layer. For asymmetric specimen with different mechanical parameters in each layer, hydraulic fracture shows an asymmetric propagation behavior, and hydraulic fracture preferentially propagates to the layer with higher elastic modulus, Poisson’s ratio, formation permeability, and low resistance.

Wellbore strengthening evaluation with core fracturing apparatus: An experimental and field test study based on preventive approach

One of the most persistent and complicated challenges during drilling a well is lost circulation, which leads to more operational cost, time, and risk. Wellbore strengthening (WBS) with the addition of special solid particles, means lost control materials (LCMs), in drilling fluid is a major solution to control the fluid loss and improve the formation pressure-bearing capacity. The preventive approach of wellbore strengthening is based on the plastering effect of mud cake to inhibit the initiation of new induced fractures or the growth of pre-existing ones. The sealing capability of the mud cake can be affected by LCM properties which has been evaluated by some plugging apparatus with slotted disk in previous researches. However, in this paper, a self-designed core fracturing laboratory setup has been developed to simulate the fracturing process of a rock sample in a more realistic situation and study the effect of LCM particles on the creation of an efficient filter cake to improve the fracture gradient of the formation. Artificial cylindrical concrete cores with a central hole have been used to eliminate the heterogeneity effect of the rock and achieve the same experimental conditions. The fracture breakdown pressure (FBP) and fracture reopening pressure (FRP) have been considered as the objective parameters for evaluation of LCM performance. The experimental results on 18 core samples with two different types of LCM and different particle size distribution show that the addition of LCM particles into drilling fluid can improve FBP and FRP up to 33 % and 72 %, respectively. This indicates that the sealing/plastering effect of mud cake can be improved by LCM properties to achieve a higher fracture pressure. In addition, different fluid systems with different LCM types and LCM sizes have various effects on the preventive approach of wellbore strengthening. Finally, one of the drilling fluid formulations with a desirable performance during laboratory tests was selected to apply for drilling the 12–1/4” hole section in one of Iranian oil fields as a preventive approach where a history of severe lost circulations had been reported. The results of field test showed that using this approach was more successful than the remedial approach used in all previous wells of this field and resulted in a significant reduction in cost and material consumption.

Numerical and experimental investigation of hydraulic fracture using the synthesized PMMA

Hydraulic fracturing is a technique used for stimulation of unconventional reservoirs including shale plays. Several parameters, including rock properties, state of stresses, and fracturing fluid characteristics, influence successful design and implementation of a hydraulic fracturing operation. Monitoring of real-time hydraulic fracture initiation and propagation in the field to improve the design parameters is costly. Several hydraulic fracturing laboratory studies have been reported; however, similar to the field operations, real-time observation of the fracturing fluid penetration to the rock sample is not practical throughout the test but the sample can only be inspected post-experiment. In this work, we present the specifications of a through see synthesized polymethyl methacrylate (PMMA) material which was made for the purpose of laboratory experimental hydraulic fracturing testing. The mechanical testing of the PMMA allowed us to obtain the mechanical properties, including tensile and compressive strengths as well as toughness are close to the typical tight samples used in the laboratory for hydraulic fracturing experiments. Hydraulic fracturing tests were performed on a number of cylindrical PMMA samples to investigate the effect of injecting fluid viscosity and flow rate as well as the geometry of the initial crack on fracture breakdown pressure and the characteristics of the propagating fracture. The ability to directly observe the fracture geometry throughout the experiment allowed us to make a good correspondence between the pressure–time curve and the evolution of the fracture geometry. Numerical modeling using ANSYS was performed to run multiple simulations and do sensitivity analysis of different parameters similar to the laboratory experiments. The results also were compared with some of the analytical solutions.

The in situ hydraulic properties of fault zones in mine roadway floor

In this study, we explored the hydraulic properties of the fault zone at different positions of roadway floor using in situ high-pressure water injection tests under controlled water injection. During the test, injecting water flow rate and pressure as well as water pressure in the monitor borehole were continuously measured and recorded. The test results showed that changes of injecting water pressure in the fault zone obey the changing characteristics of the typical hydraulic fracturing pressure. Analysis of the test results showed that the hydraulic process could be divided into original and post-fracture stages at the breakdown pressure. In the original stage, the flow dimension (v) continuously increased. In the post-fracture stage, the equivalent hydraulic fracture aperture (b) also continuously increased even when the flow rate decreased. The fracturing-induced fractures were scoured during water injection. In addition, the original hydraulic conductivity (K) of the fault zone decreased while the hydraulic fracturing breakdown pressure (P0) increased with the distance (D) of the test point to the roadway floor increasing. The main cause for these phenomena was the difference in the stress states of the fault zone at different locations of the roadway floor.

Propagation of toughness-dominated fluid-driven fractures in reactive porous media

Fluid-driven open-mode fractures in porous media are the result of multiple physical processes governed by fluid properties, porous media properties, geometrical fracture properties, and fluid injection parameters. For example, a propagating open-mode fracture in which most work is spent on creating new fracture surface rather than on moving fluid through the fracture is said to be in a “toughness-dominated” regime. However, other multiphysical phenomena such as thermal dilation and mineral-dissolution can also affect fracture propagation. This study focuses on the facilitation of fracture propagation in toughness-dominated regime by weakening of the rock at the fracture tip by injection of a reactive fluid that causes mineral dissolution. We explore this coupled problem through numerical simulation using a finite element method (FEM) formulation based on the phase-field approach in order to solve equations for fluid flow, poroelasticity, linear elastic fracture mechanics and reactive transport. We couple mechanics and reactive fluid flow by assuming that fracture toughness decreases due to increases in rock porosity caused by mineral dissolution. The numerical simulation results show that acid injection and mineral dissolution (1) lower fracture breakdown pressure and (2) can bridge a transition from toughness-dominated to viscosity-dominated fracture propagation at constant injection pressure. Our results demonstrate that acid injection can change fracture propagation regimes and enable new phenomena that are not possible in unreactive porous media. The understanding of fracture propagation patterns and geometry manipulation is critical for safe and effective use of reactive fluids in the subsurface, such as in hydraulic fracturing, harnessing of deep geothermal energy, and carbon geological sequestration applications.

Determination of the maximum allowable gas pressure for an underground gas storage salt cavern – A case study of Jintan, China

Increasing the allowable gas pressure of underground gas storage (UGS) is one of the most effective methods to increase its working gas capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture breakdown pressure. Based on the test results, the maximum allowable gas pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable gas pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating gas penetration failure and gas seepage are proposed. Results show that the maximum allowable gas pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum gas pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum gas pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable gas pressure are reliable.

Experimental Investigation on Hydraulic Fracture Propagation of Carbonate Rocks under Different Fracturing Fluids

Deep carbonate reservoirs are rich in oil and gas resources. However, due to poor pore connectivity and low permeability, it is necessary to adopt hydraulic fracturing technology for their development. The mechanism of hydraulic fracturing for fracture initiation and propagation in carbonate rocks remains unclear, especially with regard to selection of the type of fracturing fluid and the fracturing parameters. In this article, an experimental study focusing on the mechanisms of hydraulic fracturing fracture initiation and propagation is discussed. Several factors were studied, including the type of injecting fracturing fluids, pump flow rate, fracturing pressure curve characteristics, and fracture morphology. The results showed the following: (1) The viscosity of fracturing fluid had a significant effect on fracturing breakdown pressure. Under the same pump flow rate, the fracturing breakdown pressure of slick water was the lowest. Fracturing fluids with low viscosity could easily activate weakly natural fractures or filled fractures, leading to open microcracks, and could effectively reduce the fracturing breakdown pressure. (2) The fluctuations in fracturing pump pressure corresponded with the acoustic emission hits and changes in radial strain; for every drop of fracturing pressure, acoustic emission hits and changes in radial strain were mutated. (3) Under the same fracturing fluid, the pump flow rate mainly affected fracturing breakdown pressure and had little effect on fracture morphology. (4) The width of the main fracture was affected by the viscosity and pump flow rate. Maximum changes in radial strain at the fracturing breakdown pressure point occurred when the fracturing fluid was guar gum. (5) With gelled acid and cross-linked acid fracturing, the main fractures were observed on the surface. The extension of the fracturing crack was mainly focused near the crack initiation parts. The crack expanded asymmetrically; the wormhole was dissolved to break through to the surface of the specimen. (6) The dissolution of gelled acid solution could increase the width of the fracturing crack and improve the conductivity of carbonate reservoirs.

Effect of Foliation and Fluid Viscosity on Hydraulic Fracturing Tests in Mica Schists Investigated Using Distinct Element Modeling and Field Data

Several hydraulic fracturing tests were performed in boreholes located in central Hungary in order to determine the in-situ stress for a geological site investigation. At a depth of about 540 m, the observed pressure versus time curves in mica schist with low dip angle foliation shows atypical pressure versus time results. After each pressurization cycle, the fracture breakdown pressure in the first fracturing cycle is lower than the refracturing or reopening pressure in the subsequent pressurizations. It is assumed that the viscosity of the drilling mud and observed foliation of the mica schist have a significant influence on the pressure values. In order to study this problem, numerical modeling was performed using the distinct element code particle flow code, which has been proven to be a valuable tool to investigate rock engineering problems such as hydraulic fracturing. The two-dimensional version of the code applied in this study can simulate hydro-mechanically coupled fluid flow in crystalline rock with low porosity and pre-existing fractures. In this study, the effect of foliation angle and fluid viscosity on the peak pressure is tested. The atypical characteristics of the pressure behaviour are interpreted so that mud with higher viscosity penetrates the sub-horizontal foliation plane, blocks the plane of weakness and makes the partly opened fracture tight and increase the pore pressure which decreases slowly with time. We see this viscous blocking effect as one explanation for the observed increase in fracture reopening pressure in subsequent pressurization cycles.

Experimental investigation on fracture propagation modes in supercritical carbon dioxide fracturing using acoustic emission monitoring

Supercritical carbon dioxide (SC-CO2) fracturing has broad application prospects due to its potential to increase production, to reduce water requirements, and to minimize environmental impacts. To date, lowering fracture breakdown pressure and inducing multi-fractures using SC-CO2 as fracturing fluid have been recognized, but the process of fracture propagation has been poorly studied. Therefore, acoustic emission (AE) system with 12 channels is used to monitor the SC-CO2 fracturing. The results show that energy release rate of SC-CO2 fracturing is 1–3 orders of magnitude higher and the cumulative energy is also much larger compared to hydraulic fracturing. Then much available energy can be converted into driving force to generate dynamic multi-fractures. Meanwhile, the curves of cumulative energy are observed as shape of sidestep or zigzag. The SC-CO2 fracturing evolution of AE events is discontinuous, suggesting that intermittent fracture propagation occurs. The process and modes of SC-CO2 fracture propagation are proposed, respectively. The process of SC-CO2 fracture propagation can be divided into 4 stages: damage zone evolution, fracture initiation, fracture post-instability and fracture arrest. And fracture propagation modes are classified into 3 types, including single curved fracture (Type -I), fracture band (Type -II) and fracture network (Type -III). This study is helpful for designing appropriate treatment to optimize CO2 sequestration or to enhance stimulated reservoir volume.

How to Reduce Fluid-Injection-Induced Seismicity

The recent growth in energy technologies and the management of subsurface reservoirs has led to increased human interaction with the Earth’s crust. One consequence of this is the overall increase of anthropogenic earthquakes. To manage fluid-injection-induced seismicity, in this study, we propose to use an advanced fluid-injection scheme. First, long-term fluid-injection experiments are separated from short-term fluid-injection experiments. Of the short-term experiments, enhanced geothermal systems stimulations have shown a higher propensity to produce larger seismic events compared to hydraulic fracturing in oil and gas. Among the factors discussed for influencing the likelihood of an induced seismic event to occur are injection rate, cumulative injected volume, wellhead pressure, injection depth, stress state, rock type, and proximity to faults. We present and discuss the concept of fatigue hydraulic fracturing at different scales in geothermal applications. In contrast to the conventional hydraulic fracturing with monotonic injection of high-pressure fluids, in fatigue hydraulic fracturing, the fluid is injected in pressure cycles with increasing target pressure, separated by depressurization phases for relaxing the crack tip stresses. During pressurization phases, the target pressure level is modified by pulse hydraulic fracturing generated with a second pump system. This combination of two pumps with multiple-flow rates may allow a more complex fracture pattern to be designed, with arresting and branching fractures, forming a broader fracture process zone. Small-scale laboratory fluid-injection tests on granite cores and intermediate-scale fluid-injection experiments in a hard rock underground test site are described. At laboratory scale, cyclic fluid-injection tests with acoustic emission analysis are reported with subsequent X-ray CT fracture pattern analysis. At intermediate scale, in a controlled underground experiment at constant depth with well-known stress state in granitic rock, we test advanced fluid-injection schemes. The goal is to optimize the fracture network and mitigate larger seismic events. General findings in granitic rock, independent of scale, are summarized. First, the fracture breakdown pressure in fatigue hydraulic testing is lower than that in the conventional hydraulic fracturing. Second, compared to continuous injection, the magnitude of the largest induced seismic event seems to be systematically reduced by cyclic injection. Third, the fracture pattern in fatigue testing is different from that in the conventional injection tests at high pressures. Cyclic fracture patterns seem to result from chiefly generated low energy grain boundary cracks forming a wider process zone. Fourth, cyclic injection increases the permeability of the system. A combination of cyclic progressive and pulse pressurization leads to the best hydraulic performance of all schemes tested. One advantage of fatigue testing is the fact that this soft stimulation method can be applied in circumstances where the conventional stimulation might otherwise be abandoned based on site-specific seismic hazard estimates.

In-situ stresses controlling hydraulic fracture propagation and fracture breakdown pressure

In-situ stress impact on hydraulic fracturing is investigated to enhance hydraulic fracturing performance. Lithology-controlled lower and upper bounds of the horizontal stresses are proposed, and an improved stress polygon method is presented. This improved method can narrow the area of the conventional stress polygon, particularly in shales; therefore, constrain the in-situ stress estimate. The lithology-controlled stresses indicate that a shale has a higher minimum horizontal stress and can be used as a barrier of the hydraulic fracture propagation when hydraulic fracturing is performed in adjacent sandstones. However, when hydraulic fracturing is performed in a shale oil or gas formation, a stress-barrier formation may not exist on the top or the bottom of the shale reservoir, and this will cause the hydraulic fractures to propagate out of the reservoir zone. We also examine the effects of the maximum and minimum horizontal stresses, shear stresses and depletion on the fracture initiation, breakdown, propagation and containment. Shear stresses cause hydraulic fractures kinking; from this evidence, we find that a horizontal well can be drilled with a certain angle to the minimum stress direction because in most cases the hydraulic fractures eventually curve to the maximum stress direction. In addition, we propose a new method to calculate the fracture breakdown pressure based on fracture mechanics. The proposed method predicts a higher breakdown pressure than the conventional one, which may better estimate the breakdown pressure.

Integrated Analysis of Geomechanical Factors for Geologic CO2 Storage in the Midwestern United States

Many deep saline rock formations have the capacity for large-scale CO2 storage in the Midwestern United States. However, geomechanical factors are not well characterized throughout the region. In this project, subsurface geomechanical conditions were described based on geologic structures, geomechanical core tests, geophysical log analysis, fracture breakdown pressure data from oil and gas wells, and the spatial arrangement of deep saline rock formations suitable for CO2 storage. The research focused on portraying regional variations of these factors, fracture patterns in key intervals, and their impact on design and operation of CO2 injection wells and the storage process.

Coal Mine Hydraulic Fracturing Underground Drainage Research and Engineering Application

Using elastic mechanics and fracture mechanics, analyzing the coal seam hydraulic fracturing breakdown pressure, given its theoretical formula. According to hydraulic fracturing stress status, given the form of two typical hydraulic fracture morphology. Analyzing hydraulic fracturing highly elliptical shape. The displacement field in plane stress state is given, and the theoretical formula of fracturing radius of hydraulic fracturing is deduced. The fracturing technology of underground fracturing is presented, and the fracturing location and fracturing parameters are determined. In Sihe Coal Mine conducted fracturing test, the test results showed that: the average of drainage volume of fracturing hole improved 4.4 times compared with non-pressed-hole. The extraction compliance time is reduced by 38%. Roadway tunneling speed was improved by 15%. It can solve the problem of gas overrun in roadway excavation well, and has a good application and popularization value.

Interpreting Multistage Minifrac Tests using Discrete Element Modeling of Foliated Rock with Various Drilling Mud Properties

Multistage mini hydraulic fracturing tests were performed in a borehole located in central Hungary in order to determine in-situ stress. At depth of about 500 to 560 meters, observed pressure versus time curve in metamorphic rock (mica schist) show a typical results. After each pressurization cycle, the fracture breakdown pressure in the first fracturing cycle is lower than the reopening pressures in the subsequent reopening and step-rate phases. It is assumed that the composition of the drilling mud and observed foliation of the mica schist have a significant influence on the pressure values. In order to investigate this problem, numerical modeling was performed using the discrete element code (ITASCA Particle Flow Code, PFC), which has been proven as an effective tool to investigate rock engineering problems associated with hydraulic fracturing. The code presented in this study enables simulating hydro-mechanically coupled fluid flow in crystalline rock with low porosity and pre-existing fractures (represented by the smooth joint contact model in PFC) in two dimensions. In this study, the sensitivity of the effect of foliation angle and fluid viscosity on the peak pressure is tested. The anomalous characteristics of the pressure behavior are interpreted in that way that the drilling mud penetrates the sub-horizontal foliation plane, it clogs the plane of weakness and makes the opened fracture tight. Eventually, the process prevents leak-off from the opened fracture that might explain the increased fracture reopening pressure in subsequent cycles.