Fracture Propagation Pressure Research Articles

Comparative verification of discrete and smeared numerical approaches for the simulation of hydraulic fracturing

The numerical treatment of propagating fractures as embedded discontinuities is a challenging task for which an analyst has to select a suitable numerical method from a range of options. Since their inception in the mid-80s, smeared approaches for fracture simulation such as non-local damage, gradient damage or more lately phase-field modelling have steadily gained popularity. One of the appeals of a smeared implicit fracture representation, the ability to handle complex topologies with unknown crack paths in relatively coarse meshes as well as multiple-crack interaction and multiphysics, is a fundamental requirement for the numerical simulation of hydraulic fracturing in complex situations which is technically more difficult to achieve with many other methods. However, in hydraulic fracturing simulations, not only the prediction of the fracture path but also the computation of fracture width and propagation pressure (frac pressure) is crucial for reliable and meaningful applications of the simulation tool; how to determine some of these quantities in smeared representations is not immediately obvious. In this study, two of the most popular smeared approaches of recent, namely non-local damage and phase-field models, and an approach in which the solution space is locally enriched to capture a strong discontinuity combined with a cohesive-zone model are verified against fundamental hydraulic fracture propagation problems in the toughness-dominated regime. The individual theoretical foundations of each approach are discussed and differences in the treatment of physical and numerical properties of the methods when applied to the same physical problems are highlighted through examples.

Numerical study of horizontal hydraulic fracture propagation in multi-thin layered reservoirs stimulated by separate layer fracturing

ABSTRACTSeparate layer fracturing (SLF) technique is the prevailing method for stimulating multi-thin layered reservoirs (MTLRs) whereas the production record reveals that not all wells show good performance after being fractured. The primary cause for this phenomenon can be attributed to the complex geometry of the created hydraulic fractures. For better understanding the problem, we establish a new geomachanical model based on the extended finite element method (XFEM) and cohesive zone method (CZM), to investigate the fracture propagation in MTLRs under SLF. Reverse faulting stress regime is considered. In the simulation procedure, horizontal hydraulic fractures (HHFs) are created sequentially from the bottom up along a vertical wellbore. The results show that later created HHFs will propagate out of the pay zones or probably enter the water or gas-bearing layers if the fracturing time is not reasonably controlled. The fracture initiation pressure (FIP) and fracture propagation pressure (FPP) present larger values when stimulating the upper formations, and the deviation of later created HHFs can lead to the building up of FPP. Parametric studies indicate that larger injection rate and shallower reservoir depth yields longer and wider HHFs while smaller injection rate, shallower reservoir depth and thicker barriers results in lower FIP and FPP.

Thermal wellbore strengthening through managed temperature drilling – Part I: Thermal model and simulation

This paper is the first part of a two-part series introducing a new and innovative managed temperature drilling technique for strengthening the wellbores of challenging oil and gas wells. This technique relies on heat generation within the borehole to increase the effective fracture gradient of near-wellbore zones in oil and gas wells. By releasing heat at exactly the right time and at the right location, the temperature in a near-wellbore zone can be raised, which in turn raises thermal stresses in this zone. This results in “thermal wellbore strengthening”, i.e. an increase in near-wellbore fracture initiation and propagation pressure that can be exploited to prevent or minimize induced mud losses during drilling, cementing and completion operations. As shown in Part II of this series, the heat-release is preferably achieved in a delayed fashion through the use of exothermic “heat-releasing” particles that are circulated to the zone(s) of interest in a dedicated carrier fluid.Part I describes a new computational thermal model for the proposed technique. Using finite volume techniques for an axisymmetric cylindrical geometry including a drillstring/workstring with internal and external fluid spaces, a casing string and a cementing layer (if present), and the rock formation, the model calculates the near-wellbore formation temperature as well as annulus and drill string temperature when a time-dependent and location-dependent heat generation source is acting. Model validation was conducted by comparing the simulation results from the model to analytical solutions as well as results obtained with a commercial software package for simplified cases (1D along the wellbore) with no heat source. Subsequently, near-wellbore temperature distributions were calculated for varying heat generation rates and fluid circulation times, and passed on to a geomechanical model to estimate the magnitude of the thermal strengthening effects on the fracture gradient. Results show that meaningful increases in near-wellbore stress can be obtained by the technique.The thermal wellbore strengthening technique, supported by the new thermal model described here, can be used to minimize lost circulation events and associated well trouble time and cost during drilling, cementing and completion operations, and may be particularly suited for wells with low drilling margins such as (ultra-)deepwater wells.

Understanding Lost Circulation While Cementing: Field Study and Laboratory Research

Summary Lost circulation is a time-consuming and expensive challenge, costing the oil and gas industry billions of dollars each year in materials, nonproductive time, and minimized production (Catalin et al. 2003; Fidan et al. 2004; API 65-22010). To mitigate lost circulation during cementing operations, a better understanding of how wellbore-strengthening mechanisms apply to cement slurries is necessary. The ability to control cementing-fluid properties to strengthen the wellbore and minimize losses during cementing operations is imperative for achieving adequate zonal isolation. A field analysis was performed to understand the start of lost circulation during different phases of drilling and primary cementing. Offshore wells from four different locations were studied: Gulf of Mexico (GOM), the UK, Angola, and Azerbaijan. In parallel, laboratory research was performed to understand the behavior of cement slurries in controlled lost-circulation scenarios using a block tester. Measurements of formation-breakdown pressure and fracture-propagation pressure were made with different cement-slurry compositions and compared with pressures obtained with drilling muds. In an analysis of 40 well sections that reported losses before or during primary cementing operations, the rate and severity of lost circulation varied for the wells studied, but it was concluded that losses were commonly induced while running casing or during precement-job mud circulation, but rarely during cement placement. The laboratory research confirmed the field observation: It would take much more pressure to open or reopen an existing fracture with cement slurry than with a synthetic-oil-based mud. This paper will present findings from the field analysis and laboratory research. It will also discuss strategies to prepare the wellbore for preventing losses before the cementing operation and to optimize cement formulations if losses have been induced during drilling, casing running, or prejob mud circulation.

Spatial and Temporal Variation of Seismic Attenuation During Hydraulic Fracturing of a Sandstone Block Subjected to Triaxial Stress

AbstractQ factors estimated with spectral ratios describe the attenuation experienced by seismic arrivals in their travel from the source(s) to the receiver(s). When Q is not the same along the travel path of each arrival, the formulation must incorporate two Q factors making the problem indeterminate. Here we show that by assuming that Q is a random variable, the parameters of its probability distribution can be recovered through a mapping workflow using the spectral ratios. An advantage of such a workflow is that uncertainties in source location and velocity model can also be incorporated by representing these elements as random variables. We apply such a methodology to an acoustic emission (AE) data set from a laboratory experiment of hydraulic fracturing in a Colton sandstone block. We assume that the probability distribution of Q is normal. Anisotropic mean (μQ) values correlate with the triaxial stress conditions imposed at the boundaries of the block, with higher stress corresponding with less attenuation. The μQ values estimated within time intervals in the direction perpendicular to the hydraulic fracture plane correlate with stress buildup at the borehole during fracture propagation and borehole pressure relaxation or drop during fracture closure. The standard deviations (σQ) reflect the attenuation heterogeneity within the sampled regions. An increase in heterogeneity is correlated with pressure buildup at the borehole, which we interpret to reflect a dynamic stress gradient formed from the hydraulic fracture toward the surroundings.

Pore pressure effects on fracture net pressure and hydraulic fracture containment: Insights from an empirical and simulation approach

Pore pressure and its relationship with fracture net pressure has been reported qualitatively from both field and experimental observations. From a modeling perspective, the ubiquitously used pseudo 3D (P3D) models that are based on linear elastic fracture mechanics (LEFM) do not include the effect of reservoir depletion (or overpressure). Models that utilize effective stress as propagation criteria with a cohesive zone description, introduce the pore pressure directly into the simulation and hence can potentially capture the effect of pore pressure on fracture propagation. This work investigates the effect of pore pressure on hydraulic fracturing net pressure and geometry using empirical and numerical simulation approaches. We carried out an analysis of more than 400 datafrac injections spanning a wide range of geological ages and depositional environments in order to investigate the relationship between observed net pressure and reservoir pore pressure. The net fracture propagation pressure from the fracture treatment analysis was seen to be correlated with the effective stress in the reservoir. Fracture propagation simulations were performed using a coupled finite element – finite difference fracture simulator. The code uses a cohesive zone model (CZM) to describe fracture propagation. Four different effective stress scenarios were used to study the effect of effective stress on net pressure. The simulation results closely match the empirical relation between net pressure and effective stress as obtained from the analysis of actual frac treatment data. It is observed from the simulations that the magnitude of the effective stress also has an effect on the fracture geometry with a high effective stress leading to wider, shorter and more radial fractures. The derived empirical correlation is hence useful as a fracture design parameter. The datafrac net pressure diagnostics workflow in the pseudo 3D models can incorporate local tip pore pressure as a new pressure matching parameter. The pore pressure effect can thus explain high net pressures routinely observed in frac operations and also as a containment mechanism.

Lost-Circulation Control for Formation-Damage Prevention in Naturally Fractured Reservoir: Mathematical Model and Experimental Study

Summary Drill-in fluid loss is the most important cause of formation damage during the drill-in process in fractured tight reservoirs. The addition of lost-circulation material (LCM) into drill-in fluid is the most popular technique for loss control. However, traditional LCM selection is mainly performed by use of the trial-and-error method because of the lack of mathematical models. The present work aims at filling this gap by developing a new mathematical model to characterize the performance of drill-in fluid-loss control by use of LCM during the drill-in process of fractured tight reservoirs. Plugging-zone strength and fracture-propagation pressure are the two main factors affecting drill-in fluid-loss control. The developed mathematical model consists of two submodels: the plugging-zone-strength model and the fracture-propagation-pressure model. Explicit formulae are obtained for LCM selection dependent on the proposed model to control drill-in fluid loss and prevent formation damage. Effects of LCM mechanical and geometrical properties on loss-control performance are analyzed for optimal fracture plugging and propagation control. Laboratory tests on loss-control effect by use of different types and concentrations of LCMs are performed. Different combinations of acid-soluble rigid particles, fibers, and elastic particles are tested to generate a synergy effect for drill-in fluid-loss control. The derived model is validated by laboratory data and successfully applied to the field case study in Sichuan Basin, China.

Development of a 3D numerical model for quantifying fluid-driven interface debonding of an injector well

Interface debonding is considered as a major reason for loss of well integrity of a CO2 injector. In this work, a 3D numerical model is developed for simulation of a fluid-driven debonding fracture using the coupled pore pressure cohesive zone method. The equations used in the method are described. The method is validated by numerically reproducing the results of an interface debonding experiment reported in the literature. The 3D model is used to quantify the propagation pressure and the geometry of the debonding fracture in a vertical well. The effects of several key factors in the development of debonding fractures are investigated. The results show that fracture propagation pressure is more sensitive to horizontal stress than to casing pressure. The presence of initial defects at the interface can significantly reduce the propagation pressure and the debonding fracture tends to develop vertically, rather than circumferentially at the interface. The results also demonstrate that the debonding growth is highly influenced by the cement stiffness, critical strength and toughness of the interface, illustrating the importance of appropriate cement design. The method proposed herein presents a useful step towards prediction of loss of well integrity due to interface debonding, and provides improved guidance for cement selection and injection optimization.

Parametric study of controllable parameters in fracture-based wellbore strengthening

Fracture-based wellbore strengthening techniques have been widely used in the oil industry to reduce the cost of lost circulation, especially in depleted reservoirs. Accurate prediction of induced-fracture geometry is of critical importance for best particle size distribution (PSD) selection of wellbore strengthening materials (WSM). Conventional parametric analyses mainly focused on rock properties, well conditions and WSM plug location. Thus, the deficiency of ignoring time and fluid dynamics may result in erroneous operations. In this paper, a dynamic fracture model based on the dislocation method is employed to qualitatively characterize the influence of controllable parameters on fracture propagation and fracture reopening pressure (FROP). Fracture propagation length and profile are obtained for each parameter with different values. It is found that fluid injection rate, fluid viscosity, fluid injection time, wellbore inclination and wellbore radius have an inverse relationship with FROP. On the other hand, fracture plug width has a positive relationship with FROP. Finally, a procedure for determining optimal wellbore strengthening operations by manipulating the controllable parameters is developed based on the dynamic fracture model.

Comprehensive analysis of initiation and propagation pressures in drilling induced fractures

A new experimental set-up was designed to carry out high-pressure borehole fracturing tests on cylindrical rock samples. The experimental set-up offers full control over borehole, confining, and pore pressures. Fracturing experiments were conducted on cylindrical Berea sandstone samples. Several injection cycles were carried out on each rock sample to measure the Fracture Initiation Pressure (FIP) and the stable Fracture Propagation Pressure (FPP) at various confining pressures. The measured FIP values were compared with Hubbert and Willis’ model, and Rummel's model. The stable FPPs were measured using synthetic based mud (SBM) with and without lost circulation material (LCM), and compared with the large-scale fracturing experiments conducted at the Drilling Engineering Association (DEA) 13 investigation. Our study shows that initiation of a drilling induced fracture (DIF) is best characterized by a fracture mechanics approach such as Rummel's model. The stable FPP value changes linearly with the minimum horizontal stress (Shmin), and it is independent of the maximum horizontal stress (Shmax) or the vertical stress (Sv). Also, we show that adding LCM to the drilling fluids significantly enhances the stable FPP.

Fracture plugging optimization for drill-in fluid loss control and formation damage prevention in fractured tight reservoir

Well-developed natural fractures are beneficial for the economic and efficient development of tight reservoirs. However, they also lead to drill-in fluid loss and induced severe formation damage. Fracture plugging with loss control material (LCM) is the most common way to control lost circulation. Fracture plugging effect largely depends on the fracture propagation pressure, because plugging failure is mainly caused by fracture propagation in fractured formation. Nevertheless, the effects of the plugging parameters on the fracture propagation pressure are still unclear. The current paper develops a mathematical model for fracture propagation pressure accounting for fracture plugging. Key indexes are proposed for fracture plugging optimization based on parameter analysis. Laboratory experiments are conducted to select reasonable LCM type and concentration. The application procedure of the proposed model to drill-in fluid loss control is presented and successfully applied to field case study. The modelling results show that the plugging zone length, width and permeability are the major plugging parameters that affect the fracture propagation pressure. The larger the plugging zone width and the smaller the plugging zone length and permeability, the higher the fracture propagation pressure. Maximum plugging pressure, total loss volume before sealing and D90 degradation rate are proposed as the three indexes for LCM selection. Experimental results show that the combination of rigid granule, fiber and elastic particle can create a synergistic effect to optimize the fracture plugging effect. For the 500 μm width fracture, the optimal concentrations for rigid granule, fiber and elastic particle are 5.0%, 1.5% and 2.5%, respectively.

A Review on Fracture-Initiation and -Propagation Pressures for Lost Circulation and Wellbore Strengthening

Summary Fracture-initiation pressure (FIP) and fracture-propagation pressure (FPP) are both important considerations for preventing and mitigating lost circulation. For significant fluid loss to occur, a fracture must initiate on an intact wellbore or reopen on a wellbore with pre-existing fractures, and then propagate into the far-field region. Wellbore-strengthening operations are designed to increase one or both of these two pressures to combat lost circulation. Currently, some theoretical models assume that FIPs and FPPs are only functions of in-situ stress and rock-mechanical properties. However, as demonstrated by numerous field and laboratory observations, they are also highly related to drilling-fluid properties and to interactions between the drilling fluid and formation rock. This paper discusses the mechanisms of lost circulation and wellbore strengthening, with an emphasis on factors that can affect FIP and FPP. These factors include microfractures on the wellbore wall, in-situ-stress anisotropy, pore pressure, fracture toughness, filter-cake development, fracture bridging/plugging, bridge location, fluid leakoff, rock permeability, pore size of rock, mud type, mud solid concentration, and critical capillary pressure. The conclusions of this paper include information seldom considered in lost-circulation studies, such as the effect of microfractures on FIP and the effect of capillary forces on FPP. Research results described in this paper may be useful for lost-circulation mitigation and wellbore-strengthening design, as well as hydraulic-fracturing design and leakoff-test (LOT) interpretation.

Poroelastic and Poroplastic Modeling of Hydraulic Fracturing in Brittle and Ductile Formations

SummaryThe prevailing approach for hydraulic-fracture modeling relies on linear-elastic fracture mechanics (LEFM). Generally, LEFM that uses stress-intensity factor at the fracture tip gives reasonable predictions for hard-rock hydraulic-fracturing processes, but often fails to give accurate predictions of fracture geometry and propagation pressure in formations that can undergo plastic failures, such as poorly consolidated/unconsolidated sands and ductile shales. This is because the fracture-process zone ahead of the crack tip, elasto-plastic material behavior, and strong coupling between flow and stress cannot be neglected in these formations. Recent laboratory testing has revealed that in many cases, fracture-propagation conditions cannot be described by traditional LEFM models. Rather, fractures develop in cohesive zones. In this study, we developed a fully coupled poro-elasto-plastic hydraulic-fracturing model by combining the cohesive-zone method with the Mohr-Coulomb theory of plasticity, which not only can model fracture initiation and growth while considering process-zone effects, but also can capture the effects of plastic deformation in the bulk formation. The impact of the formation plastic properties on the fracture process is investigated, and the results are compared with existing models. In addition, the effects of different parameters on fracture propagation in ductile formations are also investigated through parametric study. The results indicate that plastic and highly deforming formations exhibit greater breakdown and propagation pressure. The more plastic the formation (lower cohesion strength), the higher the net pressure required to propagate the fracture. Also, lower cohesion strength leads to shorter and wider fracture geometry. The effect of formation plasticity on a hydraulic fracture is mostly controlled by initial stress contrast, cohesion strength of formation rock, and pore pressure. We also found that altering the effective fracture toughness can only partially mimic the consequences of increased toughness ahead of the fracture tip in ductile formations, but it fails to capture the effect of shear failure within the entire affected area, which can lead to underestimating the fracture width and overestimating the fracture length. For a more-accurate modeling of fracturing in ductile formations, the entire plastic-deformation region induced by the propagating fracture should be considered, especially when shear-failure areas are large.

Numerical investigation of fracture spacing and sequencing effects on multiple hydraulic fracture interference and coalescence in brittle and ductile reservoir rocks

For unconventional resources exploration and development, hydraulic fracture pattern and associated dimensions are critical in determining well stimulation efficiency and ultimate recovery. When creating arrays of hydraulic fractures along horizontal wells, stress field changes induced by hydraulic fractures themselves can lead to fracture interference and coalescence. The resulting complex fracture geometry may compromise or improve the effectiveness of the stimulation job, depending on the nature of the context. Currently, the prevailing approach for hydraulic fracture modeling also relies on Linear Elastic Fracture Mechanics (LEFM), which uses stress intensity factor at the fracture tip as fracture propagation criteria. Even though LEFM can predict hard rock hydraulic fracturing processes reasonably, but often fails to give accurate predictions of fracture geometry and propagation pressure in quasi-brittle and ductile rocks, such as poorly consolidated sands and clay-rich shales. In this study, a fully coupled hydraulic fracture propagation model based on the Extended Finite Element Method (XFEM), Cohesive Zone Method (CZM) and Mohr–Coulomb theory of plasticity is presented, to investigate the interference and coalescence of fluid-driven hydraulic fractures that initiated from horizontal wells. The results indicate that fracture spacing and the relative timing of fracture initiation control whether the fractures compete against each other to form a divergent pattern or coalesce into a single, primary fracture. Fracture growth can be arrested after fracture tips pass by when simultaneously fracturing adjacent horizontal wells. Even though the in-elastic rock deformation due to shear failure can strongly impact fracture geometry and fracturing pressure, it has limited influence on hydraulic fracture interaction patterns.

Poro-elasto-plastic modeling of complex hydraulic fracture propagation: simultaneous multi-fracturing and producing well interference

With the increasing wide use of hydraulic fractures in the petroleum industry, it is essential to accurately predict the behavior of fractures based on the understanding of fundamental mechanisms governing the process. For effective reservoir exploration and development, hydraulic fracture pattern, geometry and associated dimensions are critical in determining well stimulation efficiency. In shale formations, non-planar, complex hydraulic fractures are often observed, due to the activation of preexisting natural fractures and the interaction between multiple, simultaneously propagating hydraulic fractures. The propagation of turning non-planar fractures due to the interference of nearby producing wells has also been reported. Current numerical simulation of hydraulic fracturing generally assumes planar crack geometry and weak coupling behavior, which severely limits the applicability of these methods in predicting fracture propagation under complex subsurface conditions. In addition, the prevailing approach for hydraulic fracture modeling also relies on linear elastic fracture mechanics (LEFM) by assuming the rock behaves purely elastically until complete failure. LEFM can predict hard rock hydraulic fracturing processes reasonably, but often fails to give accurate predictions of fracture geometry and propagation pressure in ductile and quasi-brittle rocks, such as poorly consolidated/unconsolidated sands and ductile shales, even in the form of simple planar geometry. In this study, we present a fully coupled poro-elasto-plastic model for hydraulic fracture propagation based on the theories of extend finite element, cohesive zone method and Mohr–Coulomb plasticity, which is able to capture complex hydraulic fracture geometry and plastic deformations in reservoir rocks explicitly. To illustrate the capabilities of the model, example simulations are presented including ones involving simultaneously propagating multiple hydraulic fractures and producing well interference. The results indicate that both stress shadow effects and producing well interference can alter hydraulic fracture propagation behavior substantially, and shear failure in ductile reservoir rocks can indeed make a significant difference in fracturing pressure and final fracture geometry.

Coupled flow-stress-damage simulation of deviated-wellbore fracturing in hard-rock

In this study, the evolution of hydraulic fractures and micro-annuluses around wellbores was simulated using zero-thickness Pore Pressure Cohesive Elements (PPCE). A coupled flow-stress-damage (FSD) nonlinear finite element model which consists of deviated wellbore, perforation hole, micro-annulus, cement sheath and casing was established. The viscoelastic continuum damage induced by hydraulic fracturing is governed by the traction-separation law. Mohr-Coulomb law is used to determine the elastic and plastic behaviors of the cement sheath and surrounding rock. Numerical results show that micro-annulus propagates around the wellbore firstly, then it would gradually close. In addition, the sensitivities of rock parameters and in-situ stresses were also analyzed. It is found that, in the strike-slip stress regime, the width of fracture increases with the increasing deviated angle of wellbore. The fracture length increases with the increasing deviated angle of wellbore if the angle is smaller than 45°. However, if the deviated angle is above 45°, the fracture length decreases when the angle increases. When the bulk modulus is greater than 90 GPa, the fracture geometry keeps nearly unchanged. A higher Poisson's ratio increases the fracture propagation pressure and the in-situ stress differences can not effectively restrict the fracture height growth in hard formation.

Mechanism of fracture initiation and propagation using a tri-axial hydraulic fracturing test system in naturally fractured reservoirs

A series of laboratory hydraulic fracture experiments was conducted on synthetic rock samples to investigate the mechanism of hydraulic fracture initiation and propagation of a pressurised wellbore in non-fractured and fractured reservoirs. To achieve this goal, the influence of pre-existing fracture (both on and far from the wellbore wall) and horizontal differential stress was investigated on the fracture initiation and propagation in different stress regimes. In reservoirs with no fracture due to the high stress concentration in surrounding rock of the well, the fracture initiation and propagation pressure are increased. In fractured reservoirs, the presence of pre-existing fracture on the wellbore wall reduced the effect of the original stress concentration around the wellbore, which led to a drastic decrease in the fracture initiation and propagation pressure. In the far-wellbore region by increasing dip and strike of the pre-fracture, the fracture propagation pressure was decreased when it intersected the pre-fracture and arrest behaviour of the fracture was also decreased. In-situ horizontal differential stress, () played an important role on the fracture propagation behaviour and the fracture initiation and propagation pressure both in non-fractured and fractured reservoirs. Unlike low differential stress, at high differential stress due to decreasing the interaction between hydraulic and pre-existing fractures, the dominant behaviour of fracture propagation was changed from arrest to crossing mode. In addition, at high differential stress because of decreasing the stress state concentration around the wellbore, initiation and propagation pressure of the hydraulic fracture were decreased.

Model for fracture initiation and propagation pressure calculation in poorly consolidated sandstone during waterflooding

During the process of waterflooding, the water injection pressure needs to be increased to improve the water absorption capability of formation. However, the injection pressure should be less than the fracturing pressure. Otherwise, it will cause lots of problems, such as casing failure, caprock damage and the reactivation of faults. The past works indicate that fracturing in poorly consolidated sandstone is different from fracture growth in brittle competent rocks due to strong poroelastic effect and low strength. This paper describes a new model with the consideration of fluid flow and thermal effect to calculate the fracture initiation and propagation pressure. The fracture initiation and propagation criterion for poorly consolidated sandstone is different from the conventional stress intensity factor approach and a new shear criterion with the consideration of the conjugate shear plane direction is proposed. Base on the mechanical and physical properties parameters from Bohai Bay in China, the stresses around the wells during water injection are calculated to determine the failure mode. And the fracture initiation and propagation pressure are obtained with the model. The results of the study show that the fracture in poorly consolidated sandstone during water injection is dominated by shear failure, and the fracture is perpendicular to the minimum horizontal stress. The fracture initiation pressure is less than that calculated by the traditional approaches and is related to the in-situ stress, rock strength, water temperature, water injection rate and Biot's constant. The fracture propagation pressure is related to the in-situ stress, fracture length, rock strength, water temperature, water injection rate and permeability of the fracture. Through this study, the maximum injection pressure can be determined during water injection in poorly consolidated sandstone. In addition, this study could also have application in other areas, such as wellbore stability, sand production, frac-packing.

The influence of pumping parameters in fluid‐driven fractures in weak porous formations

SummaryIn this work, we investigate the main pumping parameters that influence a fluid‐driven fracture in cohesive poroelastic and poroelastoplastic weak formations. These parameters include the fluid viscosity and the injection rate. The first parameter dominates in the mapping of the propagation regimes from toughness to viscosity, whereas the second parameter controls the storage to leak‐off dominated regime through diffusion.The fracture is driven in weak permeable porous formation by injecting an incompressible viscous fluid at the fracture inlet assuming that the fracture propagates under plane strain conditions. Fluid flow in the fracture is modeled by lubrication theory. Pore fluid movement in the porous formation is based on the Darcy law. The coupling follows the Biot theory, whereas the irreversible rock deformation is modeled with the Mohr–Coulomb yield criterion with associative flow rule. Fracture propagation criterion is based on the cohesive zone approach. Leak‐off is also considered. The investigation is performed numerically with the FEM to obtain the fracture opening, length, and propagation pressure versus time.We demonstrate that pumping parameters influence the fracture geometry and fluid pressures in weak formations through the viscous fluid flow and the diffusion process that create back stresses and large plastic zones as the fracture propagates. It is also shown that the product of the propagation velocity and fluid viscosity, µv that appears in the scaling controls the magnitude of the plastic zones and influences the net pressure and fracture geometry. These findings may explain partially the discrepancies in net pressures between field measurements and conventional model predictions for the case of weak porous formation. Copyright © 2014 John Wiley & Sons, Ltd.

Prevention of fracture propagation to control drill-in fluid loss in fractured tight gas reservoir

Developed fractures are beneficial for the economic and efficient development of tight gas reservoir. But they will lead to drill-in fluid loss and induce serious formation damage. Preventing natural fractures propagation is the key to control drill-in fluid loss in the fractured reservoir. Plugging and sealing the fracture loss channel with loss control material (LCM) can improve the fracture propagation pressure (FPP) effectively. However, the main parameters that affect the improved FPP are not clear. To our best knowledge, few papers have been published on the comprehensive parametric analysis for improved FPP to select reasonable LCM and control drill-in loss in fractured tight gas reservoir. In this paper, we develop a mathematic model to analyze the parameters that affect the FPP after plugging. Laboratory experiment is conducted to select reasonable LCM based on the parametric analysis. Study results show that formation stress anisotropy, elastic modulus, fracture length, fracture pressure and plugging location are the main parameters that impact the improved FPP. According to the analysis results, maximum plugging pressure and total loss volume before sealing are proposed as the key indexes for LCM selection. Experiment results show that reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to effectively control drill-in fluid loss in fracture tight gas reservoir.