Experimental Study on Diverter Transport Through Perforations in Multicluster Fracturing of Horizontal Well

SPE Journal ◽  
2022 ◽  
pp. 1-15
Author(s):  
Lishan Yuan ◽  
Fujian Zhou ◽  
Minghui Li ◽  
Xuda Yang ◽  
Jiaqi Cheng ◽  
...  
Keyword(s):  
Large Scale ◽  
Horizontal Well ◽  
High Pressures ◽  
Flow Distribution ◽  
Experimental System ◽  
Injection Rate ◽  
Fluid Viscosity ◽  
Horizontal Wellbore ◽  
Tight Reservoirs ◽  
Large Flow

Summary Temporary plugging and diverting fracturing of the horizontal well is the primary option to promote production for tight reservoirs. Successful entry of diverters into the perforation is the basis and prerequisite for effective plugging. However, the transport behavior of the diverter during multicluster fracturing remains unclear. In this paper, we build a large-scale diverter transport experimental system, capable of conducting experiments with large flow rates and high pressures. The concerned factors include the injection rate, perforation flow ratio (PFRO), fluid viscosity, and perforation angle. The results show that the diverter transport effect is significantly different because of different flow distribution among perforations. Also, the diverter can enter the perforation only when the flow rate of the perforation reaches a certain value. In addition, the minimum critical PFRO has an “oblique L-shaped” relationship with the injection rate. Although it is difficult for the diverter to enter the perforation on the high side of the horizontal wellbore, increasing the viscosity of the carrying fluid or using a multidensity mixed diverter can effectively solve this problem. Furthermore, the field case shows that the experimentally obtained diverter transport pattern can be applied to the field to predict the location of the diverter and improve the temporary plugging effect. The findings of this work lay a theoretical foundation for subsequent temporary plugging and diverting fracturing control.

scholarly journals Ball sealer tracking and seating of temporary plugging fracturing technology in the perforated casing of a horizontal well

2021 ◽  
pp. 014459872110204
Author(s):  
Wan Cheng ◽  
Chunhua Lu ◽  
Guanxiong Feng ◽  
Bo Xiao
Keyword(s):  
Critical Parameter ◽  
Fluid Velocity ◽  
Stable State ◽  
Horizontal Wells ◽  
Terminal Velocity ◽  
Injection Rate ◽  
Fracturing Fluid ◽  
Perforation Hole ◽  
Horizontal Wellbore ◽  
Tight Reservoirs

Multistaged temporary plugging fracturing in horizontal wells is an emerging technology to promote uniform fracture propagation in tight reservoirs by injecting ball sealers to plug higher-flux perforations. The seating mechanism and transportation of ball sealers remain poorly understood. In this paper, the sensitivities of the ball sealer density, casing injection rate and perforation angle to the seating behaviors are studied. In a vertical wellbore section, a ball sealer accelerates very fast at the beginning of the dropping and reaches a stable state within a few seconds. The terminal velocity of a non-buoyant ball is greater than the fluid velocity, while the terminal velocity of a buoyant ball is less than the fluid velocity. In the horizontal wellbore section, the terminal velocity of a non-buoyant or buoyant ball is less than the fracturing fluid flowing velocity. The ball sealer density is a more critical parameter than the casing injection rate when a ball sealer diverts to a perforation hole. The casing injection rate is a more critical parameter than the ball sealer density when a ball sealer seats on a perforation hole. A buoyant ball sealer associated with a high injection rate of fracturing fluid is highly recommended to improve the seating efficiency.

A Practical Model for Water Injection Evaluation and Optimization in Typical Offshore Reservoirs Considering Formation Heterogeneity Based on Experimental Study

2021 ◽  
Author(s):  
Shijun Huang ◽  
Yuanrui Zhu ◽  
Shichao Chai ◽  
Guanyang Ding ◽  
Yicheng Xin ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Superposition Principle ◽  
Water Injection ◽  
Injection Rate ◽  
Rate Curve ◽  
Control Effect ◽  
Injection Efficiency ◽  
Profile Control ◽  
Horizontal Wellbore ◽  
Heterogeneous Formation

Abstract A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a "U" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed "U" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed "U" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.

Coupled Flow/Geomechanics Modeling of Interfracture Water Injection To Enhance Oil Recovery in Tight Reservoirs

SPE Journal ◽  
2020 ◽  
Author(s):  
Yongzan Liu ◽  
Lijun Liu ◽  
Juliana Y. Leung ◽  
Kan Wu ◽  
George Moridis
Keyword(s):  
Oil Recovery ◽  
Horizontal Well ◽  
Water Injection ◽  
Injection Rate ◽  
Natural Fracture ◽  
Tight Oil ◽  
Coupled Flow ◽  
Fracture Spacing ◽  
Tight Reservoirs ◽  
Enhance Oil Recovery

Summary Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.

Multi-Stage Large Scale Hydraulic Fracturing in Horizontal Well, a First in India

2013 ◽  
Author(s):  
Andy Sookprasong ◽  
Sergey Mikhalovich Stolyarov ◽  
Mark Sargon
Keyword(s):  
Hydraulic Fracturing ◽  
Large Scale ◽  
Horizontal Well ◽  
Multi Stage

scholarly journals Factors affecting reorientation of hydraulically induced fracture during fracturing with oriented perforations in shale gas reservoirs

2021 ◽  
Vol 15 (58) ◽  
pp. 1-20
Author(s):  
Qingchao Li ◽  
Liang Zhou ◽  
Zhi-Min Li ◽  
Zhen-Hua Liu ◽  
Yong Fang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Injection Rate ◽  
Single Fracture ◽  
Fluid Viscosity ◽  
Fracture Conductivity ◽  
Factors Affecting ◽  
Controllable Factors ◽  
Initiation Pressure ◽  
Shale Reservoirs ◽  
Induced Fractures

Hydraulic fracturing with oriented perforations is an effective technology for reservoir stimulation for gas development in shale reservoirs. However, fracture reorientation during fracturing operation can affect the fracture conductivity and hinder the effective production of shale gas. In the present work, a numerical simulation model for investigating fracture reorientation during fracturing with oriented perforations was established, and it was verified to be suitable for all investigations in this paper. Based on this, factors (such as injection rate and fluid viscosity) affecting both of initiation and reorientation of the hydraulically induced fractures were investigated. The investigation results show that the fluid viscosity has little effect on initiation pressure of hydraulically induced fracture during fracturing operation, and the initiation pressure is mainly affected by perforation azimuth, injection rate and the stress difference. Moreover, the investigation results also show that perforation azimuth and difference between two horizontal principle stresses are the two most important factors affecting fracture reorientation. Based on the investigation results, the optimization of fracturing design can be achieved by adjusting some controllable factors. However, the regret is that the research object herein is a single fracture, and the interaction between fractures during fracturing operation needs to be further explored.

scholarly journals Study on hydraulic resistance of erodible bed at the Chiyoda experimental flume

2014 ◽  
Vol 39 ◽  
pp. 81-87
Author(s):  
T. Kakinuma ◽  
T. Inoue ◽  
R. Akahori ◽  
A. Takeda
Keyword(s):  
Large Scale ◽  
Flow Distribution ◽  
Longitudinal Survey ◽  
Sand Wave ◽  
Vertical Flow ◽  
Sand Waves ◽  
Wave Development ◽  
Logarithmic Distribution ◽  
Steady Flow Condition ◽  
Experimental Flume

Abstract. The authors made erodible bed experiments under steady flow condition at the Chiyoda Experimental Flume, a large-scale facility constructed on the floodplain of the Tokachi River, and observed sand waves on the bed of the flume. In this study, the characteristics of the sand waves are examined along the longitudinal survey lines and confirmed to be dunes. Next, the authors estimated Manning's roughness coefficients from the observed hydraulic values and assumed that the rise of the coefficients attributed to the sand wave development. Finally, vertical flow distribution on the sand waves are examined, and observed velocity distribution on the crest of waves found to be explained by the logarithmic distribution theory.

scholarly journals Scale-up of the jetcutter technology

2003 ◽  
Vol 57 (12) ◽  
pp. 636-640 ◽  
Author(s):  
Ulf Pruesse ◽  
Ulrich Jahnz ◽  
Peter Wittlich ◽  
Klaus-Dieter Vorlop
Keyword(s):  
High Throughput ◽  
Large Scale ◽  
Size Range ◽  
Scale Up ◽  
Viscous Fluids ◽  
Fluid Viscosity ◽  
Efficient Technology ◽  
Particle Size Range ◽  
Hydrogel Beads ◽  
Improved Stability

The JetCutter is a new, simple and efficient technology for the high throughput encapsulation of various materials inside spherical beads. Monodisperse beads in the particle size range from approximately 0.2 mm up to several millimeters can be prepared at high throughput rates with the JetCutter. The generation of beads is not limited by the fluid viscosity. Thus, also highly viscous fluids even with high loadings of solids, can be processed, which leads to an improved stability of the resulting beads. The JetCutter technology is available in different scales and corresponding throughputs ranging from lab-scale devices (liters per day) up to large scale installations for industrial production purposes (tons per day). The application of the JetCutter for industrial purposes has been well established by geniaLab?, which currently produces more than 40 tons/year of small hydrogel beads.

scholarly journals Effects of Formation Dip on Gas Production from Unconfined Marine Hydrate-Bearing Sediments through Depressurization

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-11 ◽  
Author(s):  
Yilong Yuan ◽  
Tianfu Xu ◽  
Yingli Xia ◽  
Xin Xin
Keyword(s):  
Large Scale ◽  
Horizontal Well ◽  
Field Measurements ◽  
Production Method ◽  
Geological Structure ◽  
Horizontal Distribution ◽  
Gas Production ◽  
Well Completion ◽  
Hydrate Reservoir ◽  
Hydrate Bearing Sediments

The effects of geologic conditions and production methods on gas production from hydrate-bearing sediments (HBS) have been widely investigated. The reservoir was usually treated as horizontal distribution, whereas the sloping reservoir was not considered. In fact, most strata have gradients because of the effects of geological structure and diagenesis. In this study, based on currently available geological data from field measurements in Shenhu area of the South China Sea, the effects of formation dip on gas production were investigated through depressurization using a horizontal well. The modeling results indicate that the strategy of horizontal well is an effective production method from the unconfined Class 2 HBS. The predicted cumulative volume of methane produced at the 1000 m horizontal well was 4.51 × 107 ST m3 over 5-year period. The hydrate dissociation behavior of sloping formation is sensitive to changes in the reservoir pressure. As in unconfined marine hydrate reservoir, the sloping formation is not conducive to free methane gas recovery, which results in more dissolved methane produced at the horizontal well. The obvious issue for this challenging target is relatively low exploitation efficiency of methane because of the recovery of very large volumes of water. Consequently, the development of the favorable well completion method to prevent water production is significantly important for realizing large scale hydrate exploitation in the future.

scholarly journals Experiments with CO<sub>2</sub>-in-air reference gases in high-pressure aluminum cylinders

2018 ◽  
Vol 11 (10) ◽  
pp. 5565-5586 ◽  
Author(s):  
Michael F. Schibig ◽  
Duane Kitzis ◽  
Pieter P. Tans
Keyword(s):  
High Pressure ◽  
Large Scale ◽  
High Pressures ◽  
Co2 Enrichment ◽  
Low Flow ◽  
Cylinder Wall ◽  
Practical Applications ◽  
Sources And Sinks ◽  
Carbon Dioxide Co2 ◽  
Adsorption Desorption

Abstract. Long-term monitoring of carbon dioxide (CO2) in the atmosphere is key for a better understanding of the processes involved in the carbon cycle that have a major impact on further climate change. Keeping track of large-scale emissions and removals (sources and sinks) of CO2 requires very accurate measurements. They all have to be calibrated very carefully and have to be traceable to a common scale, the World Meteorological Organization (WMO) CO2 X2007 scale, which is maintained by the National Oceanic and Atmospheric Administration (NOAA) Earth System Research Laboratory (ESRL) in Boulder, CO, USA. The international WMO GAW (Global Atmosphere Watch) program sets as compatibility goals for the required agreement between different methods and laboratories ±0.1 µmol mol−1 for the Northern Hemisphere and ±0.05 µmol mol−1 for the Southern Hemisphere. The reference gas mixtures used to pass down and distribute the scale are stored in high-pressure aluminum cylinders. It is crucial that the standards remain stable during their entire time of use. In this study the tested vertically positioned aluminum cylinders showed similar CO2 enrichment during low-flow conditions (0.3 L min−1), which are similar to flows often used for calibration gases in practical applications. The average CO2 enrichment was 0.090±0.009 µmol mol−1 as the cylinder was emptied from about 150 to 1 bar above atmosphere. However, it is important to note that the enrichment is not linear but follows Langmuir's adsorption–desorption model, where the CO2 enrichment is almost negligible at high pressures but much more pronounced at low pressures. When decanted at a higher rate of 5.0 L min−1 the enrichment becomes 0.22±0.05 µmol mol−1 for the same pressure drop. The higher enrichment is related to thermal diffusion and fractionation effects in the cylinder, which were also dependent on the cylinder's orientation and could even turn negative. However, the low amount of CO2 adsorbed on the cylinder wall and the fact that the main increase happens at low pressure lead to the conclusion that aluminum cylinders are suitable to store ambient CO2-in-dry-air mixtures provided they are not used below 20 bar. In cases where they are used in high-flow experiments that involve significant cylinder temperature changes, special attention has to be paid to possible fractionation effects.

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