Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

2016 ◽  
Vol 56 (1) ◽  
pp. 415 ◽  
Author(s):  
Yang Fei ◽  
Mary Gonzalez Perdomo ◽  
Viet Quoc Nguyen ◽  
Zhongyu Lei ◽  
Kunakorn Pokalai ◽  
...  
Keyword(s):  
Multiphase Flow ◽  
South Australia ◽  
Fracture Propagation ◽  
Flow Simulation ◽  
Gas Production ◽  
Propagation Model ◽  
Unconventional Reservoirs ◽  
Fracturing Fluids ◽  
Water Based ◽  
Cooper Basin

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Performance evaluation of synthetic and natural polymers in nitrogen foam-based fracturing fluids in the Cooper Basin, South Australia

2020 ◽  
Vol 60 (1) ◽  
pp. 227
Author(s):  
Tuan Tran ◽  
M. E. Gonzalez Perdomo ◽  
Klaudia Wilk ◽  
Piotr Kasza ◽  
Khalid Amrouch
Keyword(s):  
High Temperature ◽  
Foam Stability ◽  
South Australia ◽  
Propagation Model ◽  
Natural Polymers ◽  
Fracturing Fluid ◽  
Additional Energy ◽  
Fracturing Fluids ◽  
Nitrogen Foam ◽  
Cooper Basin

Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.

Simultaneous Multifracture Treatments: Fully Coupled Fluid Flow and Fracture Mechanics for Horizontal Wells

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 337-346 ◽  
Author(s):  
Kan Wu ◽  
Jon E. Olson
Keyword(s):  
Fluid Flow ◽  
Fracture Propagation ◽  
Horizontal Wells ◽  
Gas Production ◽  
Propagation Model ◽  
Displacement Discontinuity ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Frictional Pressure Drop ◽  
Horizontal Wellbore

Summary Successfully creating multiple hydraulic fractures in horizontal wells is critical for unconventional gas production economically. Optimizing the stimulation of these wells will require models that can account for the simultaneous propagation of multiple, potentially nonplanar, fractures. In this paper, a novel fracture-propagation model (FPM) is described that can simulate multiple-hydraulic-fracture propagation from a horizontal wellbore. The model couples fracture deformation with fluid flow in the fractures and the horizontal wellbore. The displacement discontinuity method (DDM) is used to represent the mechanics of the fractures and their opening, including interaction effects between closely spaced fractures. Fluid flow in the fractures is determined by the lubrication theory. Frictional pressure drop in the wellbore and perforation zones is taken into account by applying Kirchoff's first and second laws. The fluid-flow rates and pressure compatibility are maintained between the wellbore and the multiple fractures with Newton's numerical method. The model generates physically realistic multiple-fracture geometries and nonplanar-fracture trajectories that are consistent with physical-laboratory results and inferences drawn from microseismic diagnostic interpretations. One can use the simulation results of the FPM for sensitivity analysis of in-situ and fracture treatment parameters for shale-gas stimulation design. They provide a physics-based complex fracture network that one can import into reservoir-simulation models for production analysis. Furthermore, the results from the model can highlight conditions under which restricted width occurs that could lead to proppant screenout.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

A Cooper Basin simulation study of flow-back after hydraulic fracturing in tight gas wells

2016 ◽  
Vol 56 (1) ◽  
pp. 369 ◽  
Author(s):  
Sume Sarkar ◽  
Manouchehr Haghighi ◽  
Mohammad Sayyafzadeh ◽  
Dennis Cooke ◽  
Kunakorn Pokalai ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
History Matching ◽  
Flow Simulation ◽  
Gas Production ◽  
Fluid Injection ◽  
Drainage Pattern ◽  
Gas Wells ◽  
Sweep Efficiency ◽  
Fracture Fluid ◽  
Cooper Basin

After fluid injection (slickwater) during hydraulic fracturing, the flow-back of fracture fluid is necessary before gas production starts. A review of fracture treatments indicates that the incomplete return of treating fluids is a reason for the failure of hydraulic fracturing and is associated with poor gas production. The aim of this study is to investigate the parameters that limit flow-back in low permeability gas wells in the Cooper Basin. The authors used numerical simulation to find the critical controlling parameters to introduce the best practice for maximising the flow-back in the Cooper Basin. Several 3D and multiphase flow simulation models were constructed for three wells in the Patchawarra Formation during fracture fluid injection, soaking time and during flow-back. All models were validated using history matching with the production data. The results show that the drainage pattern is distinctly different in the following directions: vertically upward, vertically downward, and horizontal along the fracture half-length and along the matrix. The lowest recovery is observed during the upward vertical displacements due to poor sweep efficiency. Furthermore, it is observed that drawdown does not influence the recovery significantly for upward displacements. Surface tension reduction, however, can improve sweep efficiency and improve recovery considerably. Also, the wettability of the rocks has a significant impact on ultimate recovery when the effect of gravity is dominant. The authors conclude that a significant amount of injected fluid is trapped in the formation because of poor sweep efficiency and formation of gas fingers, which results from low mobility ratio and gravity segregation.

scholarly journals Enhanced discrete phase model for multiphase flow simulation of blood flow with high shear stress

2021 ◽  
Vol 104 (1) ◽  
pp. 003685042110080
Author(s):  
Zheqin Yu ◽  
Jianping Tan ◽  
Shuai Wang
Keyword(s):  
Blood Flow ◽  
Shear Stress ◽  
Multiphase Flow ◽  
Experimental Verification ◽  
Flow Simulation ◽  
Turbulence Models ◽  
Phase Model ◽  
Force Model ◽  
Discrete Phase Model ◽  
Discrete Phase

Shear stress is often present in the blood flow within blood-contacting devices, which is the leading cause of hemolysis. However, the simulation method for blood flow with shear stress is still not perfect, especially the multiphase flow model and experimental verification. In this regard, this study proposes an enhanced discrete phase model for multiphase flow simulation of blood flow with shear stress. This simulation is based on the discrete phase model (DPM). According to the multiphase flow characteristics of blood, a virtual mass force model and a pressure gradient influence model are added to the calculation of cell particle motion. In the experimental verification, nozzle models were designed to simulate the flow with shear stress, varying the degree of shear stress through different nozzle sizes. The microscopic flow was measured by the Particle Image Velocimetry (PIV) experimental method. The comparison of the turbulence models and the verification of the simulation accuracy were carried out based on the experimental results. The result demonstrates that the simulation effect of the SST k- ω model is better than other standard turbulence models. Accuracy analysis proves that the simulation results are accurate and can capture the movement of cell-level particles in the flow with shear stress. The results of the research are conducive to obtaining accurate and comprehensive analysis results in the equipment development phase.

scholarly journals Kinetic-based Multiphase Flow Simulation

2020 ◽  
pp. 1-1 ◽  
Author(s):  
Wei Li ◽  
Daoming Liu ◽  
Mathieu Desbrun ◽  
Jin Huang ◽  
Xiaopei Liu
Keyword(s):  
Multiphase Flow ◽  
Flow Simulation

Exploring for stratigraphic traps in the Patchawarra Formation, Cooper Basin: an integrated seismic methodology

2018 ◽  
Vol 58 (2) ◽  
pp. 779
Author(s):  
Alexandra Bennett
Keyword(s):  
Complex Geometry ◽  
Imaging Techniques ◽  
South Australia ◽  
Seismic Interpretation ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Resolution ◽  
Seismic Reflectivity ◽  
Seismic Area ◽  
Cooper Basin

The Patchawarra Formation is characterised by Permian aged fluvial sediments. The conventional hydrocarbon play lies within fluvial sandstones, attributed to point bar deposits and splays, that are typically overlain by floodbank deposits of shales, mudstones and coals. The nature of the deposition of these sands has resulted in the discovery of stratigraphic traps across the Western Flank of the Cooper Basin, South Australia. Various seismic techniques are being used to search for and identify these traps. High seismic reflectivity of the coals with the low reflectivity of the relatively thin sands, often below seismic resolution, masks a reservoir response. These factors, combined with complex geometry of these reservoirs, prove a difficult play to image and interpret. Standard seismic interpretation has proven challenging when attempting to map fluvial sands. Active project examples within a 196 km2 3D seismic survey detail an evolving seismic interpretation methodology, which is being used to improve the delineation of potential stratigraphic traps. This involves an integration of seismic processing, package mapping, seismic attributes and imaging techniques. The integrated seismic interpretation methodology has proven to be a successful approach in the discovery of stratigraphic and structural-stratigraphic combination traps in parts of the Cooper Basin and is being used to extend the play northwards into the 3D seismic area discussed.

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