Perforated Wellbore Research Articles

A model for proppant dynamics in a perforated wellbore

This paper presents a model to simulate behavior of particle-laden slurry in a horizontal perforated wellbore with the goal of quantifying fluid and particle distribution between the perforations. There are two primary phenomena that influence the result. The first one is the non-uniform particle distribution within the wellbore’s cross-section and how it changes along the flow. The second phenomenon is related to the ability of particles to turn from the wellbore to a perforation. Consequently, the paper considers both of these phenomena independently at first, and then they are combined to address the whole problem of flow in a perforated wellbore. A mathematical model for calculating the particle and velocity profiles within the wellbore is developed. The model is calibrated against available laboratory data for various flow velocities, particle diameters, pipe diameters, and particle volume fractions. It predicts a steady-state solution for the particle and velocity profiles, as well as it captures the transition in time from a given state to the steady-state solution. The key dimensionless parameter that quantifies the latter solution is identified and is called dimensionless gravity. When it is small, the particles are fully suspended and the solution is uniform. At the same time, when the aforementioned parameter is large, then the solution is strongly non-uniform and resembles a flowing bed state. A mathematical model for the problem of particle turning is developed and is calibrated against available experimental and computational data. The key parameter affecting the result is called turning efficiency. When the efficiency is close to one, then most of the particles that follow the fluid streamlines going into the perforation are able enter the hole. At the same time, zero efficiency corresponds to the case of no particles entering the perforation. Solutions for the both sub-problems are combined to develop a model for the perforated wellbore. Results are compared (not calibrated) to a series of laboratory and field scale experiments for perforated wellbores. Comparison with the available computational results is presented as well. In addition, the comparison is presented in view of the parametric space defined by the dimensionless gravity and turning efficiency. Such a description allows to explain seemingly contradictory results observed in different tests and also allows to highlight parameters for which perforation orientation plays a significant role.

Experimental and numerical study of slug flow in horizontal perforated wellbore

There have been experimental and numerical studies focused on flow patterns, pressure drops, and void fractions along horizontal wellbores. Despite the fact that few studies have examined two-phase flow in a perforated horizontal wellbore. This phenomenon has been the focus of most studies on a perforated wellbore pressure drop until recently. Experimental and numerical studies are presented in this paper to analyze slug flow in a horizontal perforated wellbore with an inner diameter of 25.4 mm, a length of 2 m, and fourteen perforations evenly distributed. An ANSYS Fluent VOF model of unsteady, turbulent, and three-dimensional flow is simulated with varying water and air superficial velocities to investigate the effect of increasing axial and radial velocities on slug flow, pressure drop, productivity, void fraction, and liquid holding up along the horizontal wellbore. An investigation of three slug flow cases was conducted in the present study. At (1 m/s for Usw & 1.5 m/s for Usa) in the first case, raising the air superficial velocity to 1.6 m/s in the second case, and increasing the water superficial velocity to 2.1 m/s in the third case. Slug flow along the perforated horizontal wellbore was investigated experimentally. As a result of the research, increased axial flow has a greater impact than increased radial flow rate on slug flow, pressure drop, and productivity can be improved with axial velocity. With axial velocity increasing, productivity in case two is 38.82% higher than in case one, while in case three, with radial velocity increasing, productivity is 14.34% higher than in case one. In addition, there is good agreement between the experimental and numerical results.

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.

Experimental study on the multiple fracture simultaneous propagation during extremely limited-entry fracturing

Horizontal well with multi-stage fracturing is one of the most effective stimulation methods for unconventional reservoirs, e.g. tight oil/gas or shale. To maximize reservoir stimulation volume (SRV), tighter fracture spacing and fewer perforations are distributed in one stage during extreme limited-entry fracturing (XLEF) in recent years. However, the fracture geometries and injection pressure curve are not clear when multiple fractures with close spacing were created simultaneously in the perforated wellbore during XLEF. This study investigated the multiple fracture simultaneous propagation in the XLEF perforated wellbore based on the true tri-axial fracturing experiments. Critical factors of horizontal stress difference (HSD), the number of perforation clusters, helical/in-plane perforated method, number of perforations per cluster and fracturing fluid flowrate were investigated in detail. The results showed that, firstly, compared to one fracture produced by the helical perforated method, XLEF with the in-plane perforated method has a higher breakdown pressure and could simultaneously create multiple transverse fractures. Secondly, longitudinal fractures and a small number of curved transverse fractures occurred simultaneously under lower HSD conditions, while multiple parallel transverse fractures could be created under high HSD conditions. Thirdly, increasing the number of perforations per cluster will reduce perforation cluster effectiveness, and increasing the number of clusters will lead to the merging of multiple fractures. Finally, three relationships between pressure response and fracture geometries during XLEF, e.g. single transverse fracture, multiple transverse fractures, co-existence of longitudinal and transverse fractures, have been revealed. This study provides a meaningful perspective for the multiple fracture propagation in the perforated wellbore, which could help the field fracturing design during XLEF.

Field-Scale Experimental Study on the Perforation Erosion in Horizontal Wellbore under Real Fracturing Conditions

Limited-entry fracturing (LEF) technology is a widely used method to realize the simultaneous propagation of multiple fractures in horizontal wells. The key of this technology is to create high perforation friction to maintain the high treatment pressure in the wellbore and realize the uniform fluid entry of multi-fractures; however, high perforation friction cannot be effectively maintained due to the serious perforation erosion effect. Considering that the current laboratory studies mostly used small fluid injection flowrate, low injection pressure, and small proppant dosage, this study has developed a field-scale flow system to investigate the effect of various factors on perforation erosion under real field conditions. The filed-scale flow system uses the real fracturing trucks, proppant, and perforated wellbore, the fluid flow rate through perforation could reach 200 m/s and the injection pressure could reach 105 MPa. The effects of different parameters, such as injection flow rates, proppant concentration, proppant type, proppant size, and carrying fluid viscosity, on the perforation erosion were investigated. The experimental results show that: (1) The perforation friction during erosion goes through two stages, i.e., the roundness erosion stage and the diameter erosion stage. The reduction of perforating friction mainly occurred in the first stage, which was completed after injecting 1 m3 proppant. (2) After erosion, the perforation changes from the original circular shape to a trumpet shape, the inner diameter is much larger than the outer diameter. (3) The more serious perforation erosion is caused by the conditions of high injection flow rate, large proppant size, using ceramic proppant, and low viscosity fluid. The findings of this study can help for a better understanding of perforation erosion during the limited-entry fracturing in the horizontal wells, and also could promote the establishment of a theoretical model of perforation erosion under the field-scale conditions.

Complexity of near-wellbore hydraulic fracture morphology around perforated wells with various orientations in tight reservoir

Horizontal wells with multiple perforated fracturing is main method to improve well production in the tight formation. However, hydraulic fracture morphology remains obscure because of different horizontal stress contrast, wellbore direction, and pump rate, resulting in no guidance for perforation parameters design. To uncover the mask, a perforated wellbore fracturing model is established based on the continuous damage theory, combing with field data to investigate the effects of above three factors on hydraulic fracture morphology around wellbore. The results indicate that induced fractures could overlap and interact with each other when the wellbore is set along the direction of minimum horizontal stress. The induced fractures have narrow width because of stress shadow effecting. However, when angle between wellbore and the minimum horizontal stress direction increases, the induced fractures prefer to link up as a simple one. Moreover, induced fractures could propagate along and perpendicular to the wellbore direction under a small horizontal stress contrast, forming a complex hydraulic fracture morphology. A high pump rate resists stress shadow effecting and improves hydraulic fracture volume, but cannot decrease the complexity of near-wellbore fractures under a small horizontal stress contrast.

Simulation of a Perforated Vertical Wellbore with Near Wall Porous Media Effect

This paper aims to predict the effect of porous media permeability and perforations parameters on the pressure drop and productivity index, for the perforated vertical wellbore with six perforations and for two phase angles. The first 60ᵒ phase angle with helical distribution and the second 180ᵒ phase angle with normal distribution. In this study, a Computational Fluid Dynamics (CFD) software has been used to simulate a model of 3-D turbulent fluid flow with stander k−∈, steady-state, and single phase. The effect of the permeability of porous media, inlet mass flow rate from porous media, perforations length, and diameter of perforations are studied, for two cases of the phase angles. The results of this study show that, the pressure drop decreases with increasing permeability pf porous media, so the productivity index increasing. Also, increase of inlet mass flow rate from porous media causing an increase in the pressure drop. The perforations length has a few effects on the pressure drop and productivity index, while the diameter of perforations has a greater effect on the pressure drop.

Experimental study on hydrofracture propagation through perforated wellbore in naturally fractured Guanyinqiao calcareous mudstone under true triaxial stress

Hydraulic fracturing technology has become successful in enhancing the permeability of unconventional gas reservoirs. However, due to the geological complexity, considerable challenges remain in understanding hydraulic fracturing of calcareous mudstone. In the main production area of shale gas reservoirs in South China, the tight interlayer of Guanyinqiao calcareous mudstone widely spreads in Wufeng-Longmaxi shale, which could heighten the risk of stimulation treatments and hinder fracturing stimulation efficiency. To investigate the characteristics of hydrofracture propagation in naturally fractured Guanyinqiao calcareous mudstone, we conducted a series of fracturing tests through perforated wellbore under true triaxial stresses. The features of fracturing treatment pressure curves, effect of stress difference and natural fracture on hydrofracture geometry, perforations breakdown modes, and the distinction between calcareous mudstone fracturing and shale fracturing were analyzed. It revealed that the breakdown pressure of perforated fracturing was lower than that of the open hole fracturing, and a smaller perforation phase angle and higher horizontal stress difference could facilitate the hydraulic fracture initiation. The natural fractures mainly developed along the bedding plane, which could cause step-over or diversion of hydrofracture at weakly cemented bedding interfaces. When horizontal stress difference increased from 4 MPa to 8 MPa, the propagation orientation of the dominant hydrofracture would change from oblique mode to transverse mode. The rock brittleness and anisotropy significantly influenced fracture geometry. The hydrofracturing in less brittle and anisotropic calcareous mudstone would produce a single dominant vertical hydrofracture, by contrast, multiple hydrofractures were prone to initiate from the perforations at a lower injection pressure in brittle shale. The understanding of hydrofracture propagation through perforated wellbore in calcareous mudstone may provide some basic data for gas reservoir fracturing engineering and academic application.

Predicting the critical drawdown pressure of sanding onset for perforated wells in ultra‐deep reservoirs with high temperature and high pressure

AbstractPerforated wells in ultra‐deep sandstone reservoirs are characterized by high reservoir temperature, high formation pressure, and high production, and sand production will cause severe safety hazards to these wells. Based on Drucker‐Prager (DP) rock failure criterion, a practical analytical model for predicting critical drawdown pressure (CDP) of sanding onset for perforated wells is established by comprehensively considering the influence of drag stress, formation water production, reservoir pressure depletion, temperature difference in the perforated wellbore. The proposed model is verified by field sanding onset monitoring data. The calculation results show that CDP changes with well inclination, and it decreases with the increase in wellbore temperature difference, reservoir pressure depletion, and water saturation. However, the CDP increases with the number of perforations and the ratio of diameter to length. The optimization of perforation parameters has an important influence on sand control. This study can effectively guide the prediction of CDP and provides basis for efficient and safe development of similar ultra‐deep and high yield sandstone reservoirs.

Geometry nature of hydraulic fracture propagation from oriented perforations and implications for directional hydraulic fracturing

Abstract In this study, hydromechanical hybrid finite-discrete element method (FDEM) models were employed to investigate hydraulic fracturing from oriented perforations at the microscale. Numerical calibrations were first used to obtain the microproperties that can represent the realistic behavior of sandstone. The fracture morphology and breakdown pressure obtained from the numerical hydraulic fracturing show reasonable agreements with the experimental results, indicating that the numerical results are convincing. Then, this method was applied to investigate the effects of the differential stress, perforation angle, perforation length, and injection rate on both the geometry nature of the hydraulic fractures (HFs) and the breakdown pressure. The perforation orientation, differential stress, and injection rate are found to strongly affect the breakdown pressure and HF geometry. However, the perforation length shows a weaker effect, especially when the perforation length is larger than the wellbore diameter. Furthermore, small-scale simulations were performed to investigate the formation of connected fractures developed from multiple perforated wellbores under the concept of directional hydraulic fracturing (DHF). The different fracture propagations and geometries in the DHF model indicate that conclusions from studying hydraulic fracturing from a single perforated wellbore may provide a limited reference for hydraulic fracturing from multiple perforated wellbores. The stress shadow effects during HF interactions were identified as the primary factor that contributed to these differences. Numerical results also provide new information on the roles of several factors (differential stress, injection rate, perforation orientation, and injection sequence) in DHF. DHF could take advantage of stress shadow effects by optimizing related factors. Based on the numerical results, some implications on the design of DHF, from small-scale simulations to field-scale applications, are discussed.

A multi-perforation staged fracturing experimental study on hydraulic fracture initiation and propagation

Hydraulic fracture initiation and propagation are extremely important on deciding the production capacity and are crucial for oil and gas exploration and development. Based on a self-designed system, multi-perforation cluster-staged fracturing in thick tight sandstone reservoir was simulated in the laboratory. Moreover, the technology of staged fracturing during casing completion was achieved by using a preformed perforated wellbore. Three hydraulic fracturing methods, including single-perforation cluster fracturing, multi-perforation cluster conventional fracturing and multi-perforation cluster staged fracturing, were applied and studied, respectively. The results clearly indicate that the hydraulic fractures resulting from single-perforation cluster fracturing are relatively simple, which is difficult to form fracture network. In contrast, multi-perforation cluster-staged fracturing has more probability to produce complex fractures including major fracture and its branched fractures, especially in heterogeneous samples. Furthermore, the propagation direction of hydraulic fractures tends to change in heterogeneous samples, which is more likely to form a multi-directional hydraulic fracture network. The fracture area is greatly increased when the perforation cluster density increases in multi-perforation cluster conventional fracturing and multi-perforation cluster-staged fracturing. Moreover, higher perforation cluster densities and larger stage numbers are beneficial to hydraulic fracture initiation. The breakdown pressure in homogeneous samples is much higher than that in heterogeneous samples during hydraulic fracturing. In addition, the time of first fracture initiation has the trend that the shorter the initiation time is, the higher the breakdown pressure is. The results of this study provide meaningful suggestions for enhancing the production mechanism of multi-perforation cluster staged fracturing.

Orientation prediction of fracture initiation from perforated horizontal wells: Application in shale reservoirs

For maximum productivity enhancement when targeting low permeability formations, horizontal wells must be made to induce multiple transverse fractures. An orientation criterion for fracture initiation is developed using analytically-derived approximations for the longitudinal and transverse fracturing stresses for perforated wellbores from the literature. The validity of the criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; pertaining to low breakdown pressure and low formation tensile strength.A three-dimensional numerical model shows that contrary to existing approximations, the transverse fracturing stress from perforated horizontal wells becomes more compressive as wellbore pressure increases. This shrinks the “breakdown pressure window,” which is the range of wellbore pressures over which transverse fracture initiation takes place. This creates a second constraint for transverse fracture initiation, which is the "critical tensile strength" value. This determines the maximum formation tensile strength at which transverse fracture initiation is possible for a given in-situ stress state and perforation direction.Sensitivity analyses are performed based on data from seven unconventional shale reservoirs (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta) for horizontal wells drilled parallel to Shmin. The frequent longitudinal fracture initiation occurrence indicated suggests fracture reorientation in the near-wellbore region to be a common event, through which the propagating fractures become aligned with the preferred fracture plane (perpendicular to the least compressive principal stress). This induces near-wellbore fluid tortuosity, which in turn can lead to completions and production-related problems, such as early screenouts and post-stimulation well underperformance.

Analytical orientation criteria for drilling and completion-induced fracture initiation considering fluid infiltration from the wellbore

Analytically-developed criteria are presented for the orientation of fracture initiation in porous-permeable rocks considering fluid infiltration from non-perforated and perforated wellbores. For non-perforated wellbores, this is a fully-exact analytical solution representing the initiation of drilling-induced tensile fractures (DITFs). For perforated wells, a set of analytical approximations are derived for fracture initiation representing completion-induced hydraulic fractures (CIHFs). DITF orientation is used to constrain the in-situ stress tensor, especially in the case of transverse DITFs, which are rarer than longitudinal DITFs. Results indicate that transverse CIHF initiation only occurs over a wellbore pressure-at-breakdown window, while longitudinal CIHF initiation occurs at comparatively higher wellbore pressures. Transverse CIHF initiation however, occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. Low Biot's poroelastic coefficient and high Poisson's ratio values also aid transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted can be shown in dimensionless plots. Case studies are run on seven prolific shale plays (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus, and Vaca Muerta) using breakdown pressures from the literature. Transverse CIHF initiation is found to be a highly likely outcome, as opposed to results from past studies that neglected pore pressure effects. Based on the findings of this study, recommendations are made to practitioners to enhance their chances on achieving transverse CIHF initiation in the field. These involve slow injection rates, oriented perforation strategy and strong bonding between the casing, cement and the surrounding rock to prevent fracturing fluid leakages.

Studying the Effect of Perforation Parameters on Vertical Well Performance

This paper presents a pressure drop analysis in perforated vertical wellbores for different perforation parameters. The effect of the density of the perforations (number of perforation), the phase angle of the perforations, the diameter of the perforation and the flow rate of the crude oil from the perforations on the pressure drop and the productivity index of the perforated vertical wellbores were studied. The analysis of the vertical wellbore was performed numerically using ANSYS FLUENT 15.0 software. Three dimensional, steady-states, turbulent and incompressible fluid flow is assumed during the numerical solution of the governing equations. The results of this study show that, increased perforation density of the perforated vertical wellbore caused an increase in pressure drop, and also, decreased productivity index due to increasing the friction losses. Friction pressure drop has a significant effect on crude oil flow into the wellbore. When the main velocity is 1.5 m/s and the inlet velocity from the perforations is 2 m/s, the friction pressure drop is about 66 % and the acceleration pressure is approximately 34 % of the total pressure drop.

Study on Temperature Distribution of Perforated Horizontal Wellbore

The temperature distribution in the wellbore under different conditions was studied by using a designed horizontal well simulation experimental device. The experimental results showed that the Joule-Thomson effect was significant in perforated wellbore. When the opening mode was the same, the larger the gas flow rate, the lower the temperature in the wellbore. Furthermore, with the increase of liquid volume, the temperature drop effect decreased gradually. The more uniform the perforation distribution, the smaller the temperature change in the wellbore. With the increase of liquid volume, the influence of gas flow rate on temperature distribution decreased. The temperature gradient caused by Joule-Thomson effect decreased with the increase of wellbore holdup. At the same time, the experimental results were compared with the theoretical values. It was found that the error of the model was within 4%, which showed the reliability of predictions of the model.

Predicting the fracture initiation pressure for perforated water injection wells in fossil energy development

Water injection is widely performed to enhance oil recovery in fossil energy development. The fracture initiation pressure (FIP) is a key parameter for designing the reasonable injection pressure for micro-fracturing water injection (MFWI). In this work, a modified method was presented to accurately predict the FIP, in which the thermal effect and plugging effect were considered; moreover, the stress around perforations was analyzed. To validate our method, the field tests, including a step rate test (SRT) and a well test, were conducted to obtain the actual FIP for perforated water injection wells, and then the FIP calculated by our method was compared with a low relative error of about 1.7%. Results show that (i) a greater temperature difference between the injected water and the formation forms a greater thermal stress around perforations, resulting in a greater change in the FIP; (ii) a larger skin factor causes a greater pressure drop for the injected water flowing through a plugged area, resulting in a stronger effective stress reduction around perforations and further producing a larger FIP. Therefore, our present work illustrates a better understanding of the stress distribution around a perforated wellbore, and paves a path for a more accurate prediction of the FIP in perforated water injection wells.

The Role of Elasto-Plasticity in Cavity Shape and Sand Production in Oil and Gas Wells

Summary Previous experimental observations have shown the formation of distinct failure patterns and cavity shapes under different stress and flow conditions. With isotropic stress, spiral failure patterns with localized shear bands are likely to form. On the other hand, under anisotropic stress, V-shaped cavities, dog-ear cavities, or slit-mode cavities are usually observed. However, the mechanisms for the development of these sanding cavities have not been fully articulated. In addition, to accurately predict the onset of sanding and to predict the sand-production rate, it is crucial to capture the physics of the formation of these cavities during sand production. This paper presents a fully coupled poro-elasto-plastic, 3D sand-production model for sand-production prediction around openhole and perforated wellbores in a weakly consolidated formation. Sanding criteria are based on a combination of shear failure, tensile failure, and compressive failure from the Mohr-Coulomb theory and strain-hardening/softening. After the failure criteria are met, an algorithm for the entrainment of the sand based on the calculation of hydrodynamic forces is implemented to predict sand erosion and transport. Dynamic mesh refinement has been implemented to effectively capture the strain-localization regions. The model has been validated with multiple analytical solutions. In addition, it is applied to compare with previous sand-production experiments that have explored the different cavity shapes formed under different conditions. The model is capable of not only explaining the mechanisms responsible for each type of cavity shape but also predicting the cavity shape that will be formed under a specific set of conditions. Parametric studies for these cases provide an additional insight into the important role that the post-yield, poro-elasto-plastic properties of the sand play in controlling the sanding mechanisms and cavity development. This allows us to predict, much more accurately, the onset of sanding and the sanding rate.

Effect of horizontal wellbore on the production behavior from marine hydrate bearing sediment

Natural gas hydrate is a potentially vast energy resource for the future. However, the fundamental behavior of hydrate dissociation during energy recovery is not fully understood due to the complex interplay of phase change and multiphase flow within porous media. In this study, the effect of horizontal wellbore incorporation on the simultaneous gas and water production during the dissociation of methane hydrates in sandy sediment (0.1–0.5 mm) was investigated. A horizontal perforated wellbore was incorporated within water saturated hydrate bearing sediments of 40% hydrate, 55% aqueous and 5% gaseous phase saturation to mimic marine hydrate sediments, and the gas and water production behavior from horizontal wellbore (HW) was compared with the base case (without well) at 3 bottom hole pressures (BHPs) of 3.5, 4.0, and 4.5 MPa under a constant surrounding temperature of 281.5 K. The evolution of temperature across 12 measured locations within the 1 L sediment demonstrated the significant effect of horizontal wellbore incorporation on heat transfer within sediment. Through the incorporation of horizontal wellbore, a continuous production of gas was observed for an extended period of time as compared to the base cases without a well. The resulting cumulative gas production was enhanced by 5.5–10% at various BHPs; whereas the cumulative water production was significantly reduced by 30.8–36.9% at different BHPs from the base cases. By estimating the percentage of hydrate dissociated, it was found that the incorporation of horizontal wellbore in the current apparatus caused a slower hydrate dissociation, as reflected by a longer time to dissociate 50% (t50,h) and 90% (t90,h) of the hydrates. This study demonstrates the potential of horizontal wellbore incorporation to simultaneously enhance gas production and reduce water production, unveiling a future direction in optimizing gas recovery from hydrate reservoirs through innovative wellbore design, configurations and well placement strategies.

Near Wellbore Hydraulic Fracture Propagation from Perforations in Tight Rocks: The Roles of Fracturing Fluid Viscosity and Injection Rate

Hydraulic fracture initiation and near wellbore propagation is governed by complex failure mechanisms, especially in cased perforated wellbores. Various parameters affect such mechanisms, including fracturing fluid viscosity and injection rate. In this study, three different fracturing fluids with viscosities ranging from 20 to 600 Pa.s were used to investigate the effects of varying fracturing fluid viscosities and fluid injection rates on the fracturing mechanisms. Hydraulic fracturing tests were conducted in cased perforated boreholes made in tight 150 mm synthetic cubic samples. A true tri-axial stress cell was used to simulate real far field stress conditions. In addition, dimensional analyses were performed to correspond the results of lab experiments to field-scale operations. The results indicated that by increasing the fracturing fluid viscosity and injection rate, the fracturing energy increased, and consequently, higher fracturing pressures were observed. However, when the fracturing energy was transferred to a borehole at a faster rate, the fracture initiation angle also increased. This resulted in more curved fracture planes. Accordingly, a new parameter, called fracturing power, was introduced to relate fracture geometry to fluid viscosity and injection rate. Furthermore, it was observed that the presence of casing in the wellbore impacted the stress distribution around the casing in such a way that the fracture propagation deviated from the wellbore vicinity.

Effect of Shape and Parameters of Perforation in a Vertical Wellbore with Two Perforations (without Porous Media) on Pressure Drop

This paper present to predict the effect of diameter and length of perforation, inflow angle of perforation, inflow velocity and shape of perforation on pressure drop and then productivity index of vertical wellbore with two perforations. In this study, a Computational Fluid Dynamics (CFD) software code ANSYS CFX15.0 has been used to simulate a model of 3-D turbulent flow with stander k−∈ in a perforated vertical wellbore. The simulation for the vertical wellbore is performed by applying the laws of conservation of mass and momentum. The effect of perforation diameter and length of perforation, inflow angle, inflow types of inlet velocity to the perforation and inflow velocity for 180o and two perforations is studied. From the results of this study, the friction pressure drop is a major component of the total pressure drop and the maximum static (friction) pressure drop occurs at the location of perforation and increases with increasing the perforation diameter. For all the perforation diameter with constant length (0.15 m), the friction pressure drop is higher than 82% of the total pressure, the acceleration pressure drop is less than 16% of the pressure drop for both numerical and theoretical results. The mixing pressure drop is about 2% of the total pressure drop for the numerical results. The increase of inflow to main flow rate ratio increasing the total pressure drop and then decreasing in productivity index.