Formation Breakdown Pressure Research Articles

Application of Endothermic Fluids to Lower the Breakdown Pressure of Unconventional Reservoirs: Implications for Hydraulic Fracturing.

Unconventional hydrocarbon reservoirs are challenging media to exploit and develop for energy due to very low permeability. As such, unconventional means, such as horizontal drilling and hydraulic fracturing, are typically practiced. During hydraulic fracturing, the formation breakdown pressure is of great importance and determines the fluid pumping cost. Less attention has been given to breakdown pressure reduction for a cost-effective and enhanced hydraulic fracturing operation. The objective of this study is to explore the application of thermochemical fluids to induce thermal shock with the purpose of generating microcracks and reducing the breakdown pressure in high-temperature unconventional reservoirs. For this, thermochemical fluids of an endothermic nature (reduces the temperature when mixed) and Kentucky Sandstone and Eagle Ford Shale were utilized. In particular, we investigated the effect of endothermic reactions between ammonium chloride (NH4Cl) and sodium hydroxide (NaOH) on the strength and breakdown pressure of both samples by applying multiple cycle treatments. The obtained results indicated a significant reduction in both the strength and breakdown pressure of the rocks, with Kentucky Sandstone showing a reduction of 53.07% and Eagle Ford Shale by 34.71% in breakdown pressure. This novel approach not only provides a promising alternative to traditional fracturing methods in high-temperature reservoirs but also could bring a significant reduction in fluid pumping requirements as well as the operational cost of hydraulic fracturing.

Fracture propagation morphology and parameter optimization design of pre-CO2 hybrid fracturing in shale oil reservoirs, Ordos Basin

Shale reservoirs typically exhibit the characteristics of large burial depth, low permeability, and well-developed bedding. Despite the implementation of water-based fracturing techniques with high displacement, attaining the optimal reservoir stimulation effect remains a formidable challenge. Consequently, in recent years, a novel method of hybrid fracturing method using pre-CO2 + sand-carrying slick water has been proposed. Within this framework, the meticulous design of fracturing operation parameters stands out as a pivotal factor influencing the efficacy of reservoir stimulation. This paper presents a coupled 3-D hydraulic fracture propagation model, investigating the influence of injection displacement, injection volume, and three-stage pre-injection fluid volume ratio on the fracture propagation. Two quantitative evaluation metrics, namely fracture surface area S and fracture transverse plane fractal dimension D, are precisely defined. Additionally, real-time analysis of bottom-hole pressure is conducted to further comprehend the dynamics of the process. Numerical investigations have revealed that both pre-CO2 injection displacement and volume exert a substantial influence on fracture half-length and complexity. Furthermore, the proportion of hybrid fracturing fluid demonstrates a notable impact on fracture height and complexity. The design of injection parameters does not exhibit a significant effect on the formation breakdown pressure. This study quantitatively evaluates fracture propagation under different working conditions from the perspective of fracture morphology, and serve as practical guidance for optimizing the process parameters design for hybrid fracturing in shale oil reservoirs, Ordos Basin.

Blowout-Capping-Fracturing-Relief Well: A Full Cycle Workflow

Summary Failed well-capping attempts following offshore-well blowouts undergoing worst case discharge (WCD) can lead to fluid-driven tensile failures (de facto hydraulic fracture initiations). Subsequent propagation of these fractures may lead to broaching of overburden-rock-formation layers and even the seafloor, providing pathways for reservoir hydrocarbons to escape into the seawater. After capping stack shut-in, the pressure buildup in the fluid column inside the wellbore exposes vulnerable locations to tensile (Mode I) failure. If this shut-in wellbore pressure exceeds the formation breakdown pressure (FBP) in any of the exposed-rock-formation layers, a fracture will initiate and will continue to propagate as long as sufficient energy is provided by the reservoir. Scenarios where the propagating fracture(s) broached the seafloor in the past led to severe environmental impacts, disturbing the local ecology. The quintessential example is Union Oil’s 1969 “A-21 Well” blowout in California’s Santa Barbara Channel, where subsequent well-capping attempts led to multiple broaching instances on the seafloor near the well with thousands of hydrocarbon gallons gushing into the seawater (observable from the sea surface as “oil boilups”). In this paper, numerical modeling is performed on a hypothetical case study using deepwater Gulf of Mexico parameters in order to evaluate the likelihood of a similar scenario by modeling a planar-fracture propagation longitudinally-to-the-wellbore, upon well capping. A workflow is developed that integrates post-blowout WCD flowrate and volume estimations, fracture initiation and propagation modeling following the capping stack shut-in, pertaining to a “cap-and-contain” strategy (including predictions in regard to seafloor broaching), along with relief-well intersection followed by kill-weight-mud injection. The casing-shoe depth is the presumed location of fracture initiation, assuming perfect integrity of all casedhole sections above it. Several sensitivity analyses are performed to investigate the impact of the casing-shoe depth, along with the stiffness of the overburden-rock-formation layer, and the post-blowout-discharge duration on the resultant fracture growth. Finally, the mud density and pump flowrate necessary to compensate the oil column to successfully kill the blown well are quantitatively assessed.

In situ stress determination in isotropic and anisotropic rocks and its application to a naturally fractured reservoir

Anisotropies exist in many sedimentary rocks, particularly in naturally fractured reservoirs, causing horizontal stress anisotropies. Case studies indicate that when a rock formation contains high dip-angle fractures or contains horizontal factures (e.g. bedding planes), it has very distinguished horizontal stresses. In these cases, the conventional isotropic method for estimating horizontal stresses may give erroneous results. Using the theory of anisotropy, horizontal stresses in the vertical transverse isotropy (VTI) and horizontal transverse isotropy (HTI) models are derived for determining in situ stresses in naturally fractured rocks. Comparing with the isotropic model, the VTI model predicts a higher minimum or maximum horizontal stress, which is suitable for shales. In contrast, the HTI model gives a lower minimum stress than the isotropic model. A combined model based on the VTI and HTI models is proposed for estimating the minimum horizontal stress in a naturally fractured formation containing natural fractures with different dip angles. Measured data in the Xujiahe gas reservoir in China reveal that the minimum horizontal stresses and formation breakdown pressures decrease as the fracture dip angles increase, which is consistent to the derived HTI model. Natural fractures can result in a decrease of the minimum horizontal stress by up to 3 MPa/km and a reduction of the formation breakdown pressure by up to 10 MPa/km in the studied area. Combining the proposed anisotropic model to the measured data of natural fractures and horizontal stresses, the assessment of in situ stresses and their impact on hydraulic fracturing are proposed. Case study demonstrates that the proposed model gives a good prediction of the minimum horizontal stresses in the naturally fractured reservoir.

A Hybrid Data-Driven/Physics-Based Modeling Approach for Hydraulic Fracture Initiation and Early-Phase Propagation in Shale

Optimal hydraulic fracture (HF) initiation and early-phase propagation results in minimal near-wellbore tortuosity, decreasing the likelihood of screenouts and maximizing the resultant well productivity. While most predictive models for the HF geometry produced in a treatment consider the far-field region, the near-well vicinity should be an integral part of a properly-engineered reservoir stimulation strategy. In this work, a novel hybrid data-driven/physics-based approach is elaborated for modeling HF initiation and early-phase propagation from perforated horizontal wells.A treatment-optimization scheme via oriented perforating is presented using the developed hybrid model, considering the orientation of the induced HF initiation (longitudinal or transverse with respect to a well drilled along the minimum horizontal in-situ principal stress) and the resultant formation breakdown pressure (FBP). Transverse HF initiation and early-phase propagation is ideal for wells drilled in low-permeability “tight” formations, while FBP minimization suppresses the overall on-site hydraulic horsepower (HHP) requirements. The demonstrated optimization scheme is applied separately to the in-situ stress states of seven prolific shale plays from the U.S. and Argentina, suggesting oriented-perforating strategies that target the promotion of transverse HF initiation in two of these (Barnett and Marcellus), while suggesting oriented-perforating strategies that target FBP minimization in the remaining five (Bakken, Fayetteville, Haynesville, Niobrara, and Vaca Muerta). The effectiveness of oriented-perforating can potentially be compromised by fracturing fluid leakages around the casing’s circumference, which is shown to hinder transverse HF initiation.The hybrid-modeling approach is also used to estimate fracture initiation pressure (FIP) values for the seven shale plays studied, indicating significant discrepancies with analytical expressions traditionally used to approximate these FIPs in modern HF computational simulations. This sets the basis for expanding this hybrid-modeling approach over a range of in-situ stress states, incorporating aggregate data-driven (numerically-derived) correction factors in order to compensate for inaccuracies in the analytical approximations, which comprise the physics-based core of the proposed hybrid model.

Hydraulic fracture initiation for perforated wellbore coupled with the effect of fluid seepage

Hydraulic fracturing technology is one of the most effective well stimulation techniques for low-permeability reservoirs, however, the mechanism of the fracture initiation and propagation is not fully understood. Based on Biot’s consolidation theory and linear elasticity theory, this paper develops a general analytical model to investigate the hydraulic fracture initiation from arbitrarily spiral perforation or oriented perforation coupled with the effect of fluid seepage. The analytical solution can be used to determine formation breakdown pressure, the location and direction of an initial crack, and to investigate the factors that affect the formation breakdown pressure and the fracture initiation position. The calculation results show that the direction of fracture initiation does not always align with the direction of the maximum horizontal principal stress and may deviate from the 0° direction of the perforation circumferential angle to the 90° direction. The seepage effect of fracturing fluid can significantly reduce the formation breakdown pressure and increase the possibility of fracture initiation from the tip of perforation. The smaller the formation depth and transfer factor (TF) are, the more favorable the fracture initiation at the tip of the perforation is. With the increase of the Biot coefficient, the formation breakdown pressure decreases significantly. To avoid the failure of cement sheath induced by the fracture initiation from the bottom of perforation, the low-viscosity fracturing fluid with a stronger seepage effect and the casings with harder materials and lower transfer coefficient are recommended.

Port-Opening Falloff Test: A Complementary Test to Diagnostic Fracture Injection Test

Summary Conventional fracture injection/falloff tests, such as minifrac or diagnostic fracture injection test (DFIT), are commonly used to characterize shale and tight reservoirs. For ultralow-permeability reservoirs, a reliable DFIT requires a long falloff period after a short injection period. A long falloff observation period of weeks or months is often not economically viable. In addition, the recent economic downturn requires operators to seek cost-effective alternatives to further optimize expenditures. An alternative to a DFIT is a port-opening falloff test (POFOT). Many horizontal completions use a pressure-activated sleeve in the toe of the well to provide formation access after the casing integrity test. Most sleeves open at a pressure in excess of the formation breakdown pressure, after which the wellbore pressure declines toward reservoir pressure. This study first introduces the concept of the POFOT as a novel physical test. A new test method must demonstrate that it accesses the formation of interest and that the data obtained are applicable. A workflow is developed to demonstrate this and is applied to falloff data from POFOTs conducted in five horizontal wells completed in five formations. The results show that the fluid leaving the port is highly likely to break down both the cement sheath and the matrix and create a fracture which then closes. Observation of the well pressure after port opening resembles that from a DFIT. However, without a fixed-duration and constant-rate injection period, there is no accepted method to apply. Nevertheless, both qualitative and quantitative analyses of the falloff data provide a good estimation of reservoir pressure with a reasonable approximation of fracture closure when compared with the estimates from DFIT analysis from offset wells. The key challenges in parameter estimation, besides the development of an appropriate analysis method, are short falloff data and noisy early-time data due to wellbore resonance (WBR), low-resolution gauges, and change in sampling frequency.

Impact of HCl Acidizing Treatment on Mechanical Integrity of Carbonaceous Shale.

Hydrocarbon production from unconventional resources especially shale reservoirs has tremendously increased during the past decade. Eagle Ford shale formation is one of the major sources of oil and gas in United States. However, due to extremely low permeability of this formation, stimulation treatments are implemented for hydrocarbon production. Eagle Ford shale requires a very high breakdown pressure during fracturing treatment due to high mechanical strength and low permeability. This study aims to address these challenges through applying the acidizing treatment on the shale and studying its impact. A detailed experimental investigation was carried out in this work to evaluate mechanical integrity and mineralogical and morphological changes of the shale formation when exposed to HCl acidizing treatment. Two crucial aspects of acidizing treatment, that is, impact of acid concentrations and treatment time, were given additional focus in this study. Different parameters such as porosity, nanopermeability, uniaxial compressive strength (UCS), acoustic velocities, dynamic elastic parameters, rock surface hardness (RSH) and brittleness index (BI) were analyzed before and after the acidizing treatment for different HCl concentrations. Microimaging was done through scanning electron microscopy (SEM) and whole cores were scanned using medical computed tomography (MCT) to understand the small-scale features. X-ray diffraction was used for the minerals’ identification. A continuous profile of UCS was measured through the scratch test system. Post-treatment results revealed that HCl treatment has a profound impact on rock mechanical properties of Eagle Ford shale. Considerable mass loss in core plugs was recorded after treatment at each concentration. Mineralogical composition and microimaging revealed compositional changes and porosity enhancement after the treatment. Reaction rate is higher in the first 10 min for higher acid concentrations resulting in significant changes in properties in that time interval. UCS and RSH exhibited a progressive decrease with increasing concentrations. The rate of RSH reduction increased with the increase in acid concentration nonlinearly. Acoustic velocities exhibited a considerable decrease even at low acid concentrations due to the enhancement of pore spaces. Noticeable reduction was observed in dynamic rock stiffness and BI with the increase in acid concentrations. On the contrary, Poisson’s ratio showed a significant increment. Experimental findings of this research can be used to optimize the acidizing treatment for Eagle Ford shale and other similar formations. Formation breakdown pressure can be reduced significantly by applying the acid treatment to improve the production of hydrocarbons. Furthermore, a better understanding of matrix acidizing can lead to savings in time and resources during production operations.

Rock Mechanical Properties and Breakdown Pressure of High-Temperature and High-Pressure Reservoirs in the Southern Margin of Junggar Basin

The mechanical properties of the high-temperature and high-pressure reservoirs in the southern margin of Junggar Basin have not been clearly understood, which correspondingly results in uncertainties when predicting the breakdown pressure. To address this issue, firstly, rock mechanical experiments under high temperature, high confining pressure, and high pore pressure were carried out. Secondly, empirical formulas related to the transformation of dynamic and static mechanical parameters in the regional strata were proposed. Finally, the existing prediction model for the formation breakdown pressure was improved by taking the wellbore seepage and thermal stress into consideration. Results show that under the reservoir condition of high temperature and high pressure, the rock sample tends to form closed shear cracks. High temperature causes thermal damages and the reduction of the compressive strength and elastic modulus, while the combined effects of high confining pressure and pore pressure enhance the compressive strength and plasticity of the rock sample simultaneously. Based on the correlation analysis, it is found that the static elastic modulus is linearly related to the dynamic value, while static Poisson’s ratio is a quadratic function of the dynamic value. These fitting functions can be used to obtain the profiles of static elastic modulus and Poisson’s ratio based on their dynamic values from the logging interpretation. Besides, the improved prediction model for the rock breakdown pressure can yield more accurate results indicated by the error less than 2%. Therefore, the proposed breakdown pressure prediction model in this study can provide theoretical guidance in the selection of fracturing truck groups and the design of the pumping schedule for high-temperature and high-pressure reservoirs.

Near-wellbore fracture initiation and propagation induced by drilling fluid invasion during solid fluidization mining of submarine nature gas hydrate sediments

Drilling in a natural gas hydrate formation is challenging due to the poor consolidation of the formation and the potential evaporation of the hydrate. The unreasonable down-hole pressure of the drilling fluid can not only lead to the wellbore instability, but also change the predrilling condition of the natural gas hydrate formation, thus leading to an instable wellbore. In this paper, the integrated discrete element method (DEM)-computational fluid dynamics (CFD) work flow is developed to study the wellbore instability due to the penetration of the drilling fluid into the hydrate formation during crack propagations. The results show that the difference between in-situ stresses and overpressure directly affect the drilling fluid invasion behavior. The lower hydrate saturation leads to an easier generation of drilling fluid flow channels and the lower formation breakdown pressure. The breakdown pressure increases with the increase of hydrate saturation, this also indicates that hydrates can enhance the mechanical properties of the formation. The induced cracks are initially accompanied with higher pressure of the drilling fluid. According to the rose diagram of the fracture orientation, a wider orientation of the fracture distribution is observed at higher pressure of the invasion fluid.

Investigation of Water Composition on Formation Damage and Related Energy Recovery from Geothermal Reservoirs: Geochemical and Geomechanics Insights

The main challenge in extracting geothermal energy is to overcome issues relating to geothermal reservoirs such as the formation damage and formation fracturing. The objective of this study is to develop an integrated framework that considers the geochemical and geomechanics aspects of a reservoir and characterizes various formation damages such as impairment of formation porosity and permeability, hydraulic fracturing, lowering of formation breakdown pressure, and the associated heat recovery. In this research study, various shallow, deep and high temperature geothermal reservoirs with different formation water compositions were simulated to predict the severity/challenges during water injection in hot geothermal reservoirs. The developed model solves various geochemical reactions and processes that take place during water injection in geothermal reservoirs. The results obtained were then used to investigate the geomechanics aspect of cold-water injection. Our findings presented that the formation temperature, injected water temperature, the concentration of sulfate in the injected water, and its dilution have a noticeable impact on rock dissolution and precipitation. In addition, anhydrite precipitation has a controlling effect on permeability impairment in the investigated case study. It was observed that the dilution of water could decrease formation of scale while the injection of sulfate rich water could intensify scale precipitation. Thus, the reservoir permeability could decrease to a critical level, where the production of hot water reduces and the generation of geothermal energy no longer remains economical. It evident that injection of incompatible water would decrease the formation porosity. Thus, the geomechanics investigation was performed to determine the effect of porosity decrease. It was found that for the 50% porosity reduction case, the initial formation breakdown pressure reduced from 2588 psi to 2586 psi, and for the 75% porosity reduction case it decreased to 2584 psi. Thus, geochemical based formation damage is significant but geomechanics based formation fracturing is insignificant in the selected case study. We propose that water composition should be designed to minimize damage and that high water injection pressures in shallow reservoirs should be avoided.

Study on the Seepage Force-Induced Stress and Poroelastic Stress by Flow Through Porous Media Around a Vertical Wellbore

Fluid flowing through reservoir pores not only generates poroelastic stress but also exerts seepage force on rock skeleton. However, the mechanism of seepage force is not clear. Traditional methods of analyzing wellbore stability and hydraulic fracture initiation are mainly focused on the poroelastic stress without the effects of seepage force. Based on the linear elasticity and consolidation theory, this paper analyzed the mechanism of seepage force and poroelastic stress, and presented an analytical solution for seepage force-induced stress around a vertical wellbore. It also introduced how to calculate poroelastic stress by exerting hypothetical body force and surface force. Through comparison and superposition of stress fields, this paper studied the change characteristics of the poroelastic and seepage force-induced stress under different borehole pressures and the effects of seepage force on the wellbore tensile failure. Numerical simulation results show that when fluid flows through the rock, using traditional models without considering, the effect of seepage force to calculate the borehole pressure-induced stress will result in lower calculation results. Compared with the traditional model, seepage force-induced circumferential tensile stress is larger, and the seepage force significantly reduces the formation breakdown pressure. Rocks near the borehole wall with lower permeability and larger Poisson’s ratio have a greater action of seepage force. When fluid flows through the reservoir, the effects of seepage forces cannot be ignored in the analysis of hydraulic fracturing and wellbore stability.

A holistic review on hydraulic fracturing stimulation laboratory experiments and their transition to enhanced geothermal system field research and operations

This paper presents a thorough overview of hydraulic stimulation techniques, conducted in laboratories. It further analyses field experiments and ongoing projects for geothermal energy production to investigate if the findings from the lab can be practically applied to the field. Stimulation techniques have been long used in the oil and gas industry as a means to increasing the rock permeability and consequently the reservoir’s fluid production rate. Among the different stimulation methods, hydraulic fracturing is known to be the most successful in creating new passageways in the formation. Nevertheless, the benefits of fracturing have been hindered by the handful of events in which poor planning had led to severe seismic activities. Therefore, across the globe, many efforts were dedicated to characterizing fracture creation and propagation in different rocks, not only to provide know-how for further and safer developments in the oil and gas front but also to adapt such findings to the ever-emerging field of geothermal energy recovery. In the course of this work, over 100 papers were studied. The papers included laboratory experiments on various rock types encountered in reservoirs, where parameters such as stress regime, fracture initiation pressure, formation breakdown pressure, volume, and types of fluid injected were monitored. To investigate whether or not such practices had been previously applied in geothermal energy production, a thorough study was also conducted on large-scale experimental setups constructed in the field as well as hydraulic fracturing procedures performed in operational projects, going back as far as a decade. The results show an agreement between laboratory experiments and field operations, yet naturally including individual results from cases where either the lab parameters or field characteristics were extraordinarily unique. Multiple cross-correlations were also performed between different key parameters that play a role in a fracturing process, providing trends that could be intra- or extrapolated for further research and planning. The novelty of this work is the comprehensive analysis of numerous research projects done around the world. As a result, this paper will not only be an informative and yet compacted source of information concerning previous projects, but it also points out the main factors and their relationships which need to be understood to guide a future project to success.

Effect of Seepage Force on the Wellbore Breakdown of a Vertical Wellbore

As a fluid flows through a porous media, a drag force, called seepage force in the paper, will be formed on the matrix of the media in the fluid flowing direction. However, the seepage force is normally ignored in the analysis of wellbore fracturing during hydraulic fracturing operation. In this paper, an analytical model for seepage force around a vertical wellbore is presented based on linear elasticity theory, and the effect of the seepage force on wellbore breakdown has been analyzed. Also studied are the effects of the two horizontal principal stresses and the reservoir permeability on the action of seepage force. The paper proves that seepage force lowers formation breakdown pressure of a vertical wellbores; the deeper a formation is, the greater action of the seepage force; seepage force contributes more to breakdown formation with small difference of the two horizontal stresses such as unconventional reservoirs; seepage force increases as rock permeability decreases, and it should not be ignored in hydraulic fracturing analysis, especially for low-permeability formation.

Verification of Coupled Hydraulic Fracturing Simulators Using Laboratory-Scale Experiments

In this work, we aim to verify the predictions of the numerical simulators, which are used for designing field-scale hydraulic stimulation experiments. Although a strong theoretical understanding of this process has been gained over the past few decades, numerical predictions of fracture propagation in low-permeability rocks still remains a challenge. Against this background, we performed controlled laboratory-scale hydraulic fracturing experiments in granite samples, which not only provides high-quality experimental data but also a well-characterized experimental set-up. Using the experimental pressure responses and the final fracture sizes as benchmark, we compared the numerical predictions of two coupled hydraulic fracturing simulators—CSMP and GEOS. Both the simulators reproduced the experimental pressure behavior by implementing the physics of Linear Elastic Fracture Mechanics (LEFM) and lubrication theory within a reasonable degree of accuracy. The simulation results indicate that even in the very low-porosity (1–2 %) and low-permeability ({10}^{-18} {mathrm{m}}^{2}- {10}^{-19} {mathrm{m}}^{2}) crystalline rocks, which are usually the target of EGS, fluid-loss into the matrix and unsaturated flow impacts the formation breakdown pressure and the post-breakdown pressure trends. Therefore, underestimation of such parameters in numerical modeling can lead to significant underestimation of breakdown pressure. The simulation results also indicate the importance of implementing wellbore solvers for considering the effect of system compressibility and pressure drop due to friction in the injection line. The varying injection rate as a result of decompression at the instant of fracture initiation affects the fracture size, while the entry friction at the connection between the well and the initial notch may cause an increase in the measured breakdown pressure.

Geomechanical analysis of formation deformation and permeability enhancement due to low-temperature CO2 injection in subsurface oil reservoirs

Several benefits of CO2 injection are reported in the literature such as its ability to mitigate greenhouse gas emissions and the increase in oil recovery at a low cost. However, the correlated reservoir-engineering problems with low-temperature CO2 injection including formation damage and leakage risk are still uncertain and has not been comprehensively investigated. This research examines the effect of low-temperature CO2 on lowering of formation breakdown pressure, and the associated formation damage from a geomechanical prospective. This study presents the coupling of the equilibrium stress equation, the system energy balance equation, continuity equation, and saturation equation to develop thermoporoelastic model for the reservoir rock. We determined the cooling-induced formation damage due to decrease in temperature and thermal stresses, formation contraction and tensile stresses, and examine its effects on formation properties, stresses, joint and fracture stability. We observed that low-temperature CO2 would create a low thermal stress region and thus the formation could fail in tension. This process might increase formation permeability but it would decrease the stability of reservoir, basement and caprock. We analyzed several factors affecting formation deformation such as injection rate for both miscible and immiscible CO2 flooding, formation porosity, depth, temperature, and formation breakdown pressure. We also compared our results and findings with experimental data, finding excellent match and similar consequences. Furthermore, as a sequence of low-temperature CO2 injection, the initial formation breakdown pressure was initially at 2560 psi and it reduced to 1928 for immiscible case and 1270 psi for miscible case in the selected case study. We also propose that shallow reservoirs should be avoided for CO2 capture and storage because of stability issues.

Cyclic Injection to Enhance Hydraulic Fracturing Efficiency: Insights from Laboratory Experiments

In hydraulic fracturing applications, there is substantial interest to reduce the formation breakdown pressure. Previous research results show that the cyclic injection method can be used to reduce that pressure. In this study, we conducted laboratory hydraulic fracturing experiments to apply cyclic injection to reduce the breakdown pressures of very tight and strong sandstones. Experimental results show that using cyclic injection the average breakdown pressure was reduced by 18.9% in very tight sandstones and by 7.18% in normal sandstones. This indicates that the effect of cyclic injection is more significant for stronger and tighter rocks. The experiments also reveal that the rock tensile strength plays a more important role in the formation breakdown pressure with a rock strength factor of 2.85. This suggests that the breakdown pressure is higher than expected. In addition, we empirically related the breakdown pressure reduction and the injection pressure amplitude to the number of injection cycles. The curve fitting results imply that the effect of cyclic injection is more important if the number of cycles or the injection pressure amplitude is increased. Based on the results of this research, the in-situ formation breakdown pressure can be reduced by applying the cyclic injection method, and the breakdown pressure reduction is more significant as the number of cycles increases.

In-situ stresses, abnormal pore pressures and their impacts on the Triassic Xujiahe reservoirs in tectonically active western Sichuan basin

Pore pressures in the Xujiahe gas-bearing formations are highly overpressured in the western Sichuan basin. The abnormally high overpressure and strong tectonic stress cause very high horizontal stresses. The high in-situ stresses, tectonic stress regimes, and tight formations severely impact development and production of the Xujiahe tight sandstone reservoirs. Overpressure generation mechanisms are analyzed based on measured data in several dozen wells in the studied gas fields. It is found that the sonic or seismic transit time can be used to predict pore pressure. Two major reservoirs (Xu2 and Xu4) belong to different fluid compartments with distinct pore pressure gradients. The Xu4 has a much higher pore pressure gradient (20 MPa/km) than the Xu2 (15.6 MPa/km).Measured data from hydraulic fracturing tests and borehole image logs in vertical wells are analyzed. The results show that the minimum horizontal stress gradient in the Xu4 reservoir reaches as high as 24 MPa/km, close to the overburden gradient. The Xu2 reservoir has a slightly lower minimum horizontal stress gradient. The high minimum horizontal stress and high rock strength cause abnormally high formation breakdown pressure gradient (24.8–34 MPa/km). The high breakdown pressure, high propagation pressure, and unfavorable stress regime result in a great difficulty for the reservoir stimulation. One of the major impacts is that hydraulic fracturing operations can only create very short hydraulic fractures, which markedly limits reservoir productivity. Based on field measurements, in-situ stress determination and assessment are given, and a new method for horizontal stress estimation is proposed. Accordingly, reliable prediction of formation breakdown and propagation pressures are proposed, which are more suitable for the tight reservoirs. Recommendations are given for effective development of the tight reservoirs with impacts of high in-situ stresses.

Geology and geomechanics of hydraulic fracturing in the Marcellus shale gas play and their potential applications to the Fuling shale gas development

Geological characteristics, geomechanical behavior and hydraulic fracture propagation mechanism in the Marcellus shale gas play are analyzed and compared with China’s Fuling shale play. Successful experiences in hydraulic fracturing and shale gas development in the Marcellus shale gas play are summarized, which might be applicable in other shale plays. The main factors contributing to the successful development of the Marcellus shale gas play include adoption of advanced drilling and completion technologies, increases of hydraulic fracturing stages, proppant concentration and fluid injection volume. The geological and geomechanical mechanisms related to those technologies are analyzed, particularly the in-situ stress impacts on hydraulic fracturing. The minimum horizontal stress controls where the fractures are initiated, and the maximum horizontal stress dominates the direction of the hydraulic fracture propagation. Hydraulic fracturing performed in the shale reservoir normally has no stress barriers in most cases because the shale has a high minimum horizontal stress, inducing hydraulic fractures propagating beyond the reservoir zone, resulting in inefficient stimulation. This is a common problem in shale plays, and its mechanism is studied in the paper. It is also found that the on-azimuth well has a higher productivity than the off-azimuth well, because shear fractures are created in the off-azimuth well, causing main fractures to kink and increasing fracture tortuosity and friction. The Fuling shale gas play has a markedly higher minimum horizontal stress and much smaller horizontal stress difference. The high minimum horizontal stress causes a much higher formation breakdown pressure; therefore, hydraulic fracturing in the Fuling shale gas play needs a higher treatment pressure, which implies higher difficulty in fracture propagation. The small difference in the two horizontal stresses in the Fuling shale gas play generates shorter and more complex hydraulic fractures, because hydraulic fractures in this case are prone to curve to preexisting fractures. To overcome these difficulties, we recommend reducing well spacing and increasing proppant concentration to increase gas productivity for the Fuling shale gas development.

Effect of the intermediate principal stress on hydraulic fracturing in granite: an experimental study

The fracturing behavior of hard rock under fluid pressure is affected by maximum, minimum, and intermediate principal stress. To investigate the effect of the intermediate principal stress on the hydraulic fracturing behavior, including the fracturing pressure, fracture pattern, fluid pressure evolution, etc., a series hydraulic fracturing experiments of granite under true triaxial compression conditions was conducted. Constant minor and major principal stresses (10 and 30 MPa, respectively) and variational intermediate principal stresses (10, 15, 20, and 25 MPa) were considered. Acoustic emission was used to monitor the hydraulic fracturing process. The effect of different intermediate principal stresses, i.e., various horizontal principal stresses, on the fluid fracturing pressure and failure pattern was studied. With higher intermediate principal stress, the hydraulic pressure fluctuates in the hydraulic fracturing process, whereas at lower intermediate principal stress, the pressure fluctuation phase becomes shorter. The higher intermediate principal stress makes the fracture plane simpler, straighter, and more planar. When the intermediate principal stress equals to the minimum principal stress, the fracture plane tends to be non-planar. In this case, the hydraulic fracture is mainly influenced by heterogeneity of the rocks. With the increase of intermediate principal stress, the formation breakdown pressure of granite decreases, which is different from the effect of minor principal stress. A modified criterion is proposed to reflect the influence of intermediate principal stress on the formation breakdown pressure.