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Collaborating Authors
Northwest Territories
Abstract Energized fluids are defined as fluids with one or more compressible gas components, such as CO2, N2, or any combination of gases, dispersed in a small volume of liquid. Generally, these fluids offer an attractive alternative to conventional stimulation fluids in many cases such as low reservoir pressure, water-sensitive formations, and/or the need for shorten flowback period. Energized fluids have many challenges such as low stability at high temperature, high friction pressure during pumping, corrosion in the case of using CO2, and the need for specialized surface pumping equipment. The objective of this paper is to describe the typical components of energized fluids and their effect on the fluid performance. Also, lab testing methods used to evaluate energized fluids performance will be discussed in detail. Foam is a class of energized fluid used for different applications including acidizing, hydraulic fracturing, and fluid diversion. For each application, foam should have a minimum acceptable value of viscosity, stability, and/or fluid compatibility. Those values were reviewed from literature and categorized based on reservoir conditions. Also, different rheological models are analyzed to understand foam flow behavior in both tubing and porous media. Finally, the mechanism of foam transport in porous media is reviewed in this report, which gives insight into foam stability and propagation. The most common application of nitrogen is in artificial lifting, while supercritical CO2 is proposed for condensate banking removal. Selection of the right surfactant, like alpha olefin sulfonates, which are thermally more stable than alkyl ether sulfates, is crucial while designing foam treatment, as they produce the most persistent foams at high salinity and elevated temperatures in the presence of synthetic and crude oils. Currently available foam-based fracturing fluid systems in the industry have temperature limitations to 300°F. The crosslinked gelled foam has a better temperature range than the viscoelastic foam fluid system, whereas non-crosslinked biopolymer-based foam fluid showed better proppant pack cleanup characteristics. In a recent report, the addition of 0.1% silica nanoparticles along with cationic surfactant was shown to enhance CO2 foam stability by 13 hours. In this review, all these aspects of energized fluids are well reported from literature. In this paper, we discuss findings from different lab testing and field demonstration of energized fluids. Compositional modelling for hydraulic fracturing with energized fluids is also reviewed to add insight on fracture geometry estimation. This paper provides guidelines and recommendations for selecting the right energized fluids for successful stimulation treatment.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (32 more...)
Abstract Successful exploitation of shale reservoirs largely depends on the effectiveness of hydraulic fracturing stimulation program. Favorable results have been attributed to intersection and reactivation of pre-existing fractures by hydraulically-induced fractures that connect the wellbore to a larger fracture surface area within the reservoir rock volume. Thus, accurate estimation of the stimulated reservoir volume (SRV) becomes critical for the reservoir performance simulation and production analysis. Micro-seismic events (MS) have been commonly used as a proxy to map out the SRV geometry, which could be erroneous because not all MS events are related to hydraulic fracture propagation. The case studies discussed here utilized a fully 3-D simulation approach to estimate the SRV. The simulation approach presented in this paper takes into account the real-time changes in the reservoir's geomechanics as a function of fluid pressures. It consists of four separate coupled modules: geomechanics, hydrodynamics, a geomechanical joint model for interfacial resolution, and an adaptive re-meshing. Reservoir stress condition, rock mechanical properties, and injected fluid pressure dictate how fracture elements could open or slide. Critical stress intensity factor was used as a fracture criterion governing the generation of new fractures or propagation of existing fractures and their directions. Simulations were run on a Cray XC-40 HPC system. The results proved the approach of using MS data as a proxy for SRV to be significantly flawed. Many of the observed stimulated natural fractures were stress related and very few that were closer to the injection field were connected. The situation is worsened in a highly laminated shale reservoir as the hydraulic fracture propagation is significantly hampered. High contrast in the in-situ stresses related strike-slip developed thereby shortens the extent of SRV. However, far field natural fractures that were not connected to hydraulic fracture were observed being stimulated. These results show the beginning of new understanding into the physical mechanisms responsible for greater disparity in stimulation results within the same shale reservoir and hence the SRV. Using the appropriate methodology, stimulation design can be controlled to optimize the responses of in-situ stresses and reservoir rock itself.
- North America > Canada (1.00)
- North America > United States > Texas (0.69)
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Residual Saturation: An Experimental Study of Effect of Gravity and Capillarity during Vertical and Horizontal flow
Adebayo, Abdulrauf R. (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia) | Barri, Assad A. (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia) | Kamal, Muhammad Shahzad (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia)
Abstract Minimum residual oil or gas saturation is desired in any oil and gas field operation while maximum residual gas saturation is desired in gas (CO2) sequestration projects. In the literature, many studies have reported various factors that affect residual saturations such as wettability, interfacial tension, viscosity ratio, and injection scheme. There have also been reports of the directional dependence of residual saturation due to anisotropy. The anisotropy is believed to be caused by variation in rock minerals and/or properties in different directions. However, the effect of the interplay between gravity and capillarity in a low velocity flow away from the injection wells during gas sequestration in saline aquifer has often been neglected in many studies. Gas flows vertically upward and against gravity at a very low rate after they have been injected into the underground aquifer. During this flow process, some key parameters that are often ignored in the laboratory estimation of the relative permeability curves that are used to model and forecast the multiphase behavior, are present. They are gravity and capillary effects. In addition, vertical upward flow core flooding experiments are rarely performed when generating relative permeability curves in the lab for CO2 sequestration modeling. In this study, the influence of the interplay between gravity and capillary forces on residual saturation during flow in horizontal and vertical direction was investigated and compared. Series of core flooding experiments at reservoir flow conditions was performed in both horizontal and vertical flow direction on different rock samples of varying mineralogy and permeability. Results obtained so far indicate directional dependence of residual saturation even for homogeneous and isotropic rocks. Residual fluid saturation is higher when flow is in vertical direction as compared to horizontal flow direction. It was concluded that directional dependence of end saturation is not due only to heterogeneity but also due to the flow direction itself as observed in homogeneous and isotropic rocks tested.
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.70)
- Research Report > Experimental Study (0.50)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Fractured Well Productivity: Proppant Pack vs. Pillar Fracture - Numerical Study
Gomaa, Ahmed M. (EXPEC-Advanced Research Center, Saudi Aramco, Dhahran 31311, Saudi Arabia) | San-Roman-Alerigi, Damian P. (EXPEC-Advanced Research Center, Saudi Aramco, Dhahran 31311, Saudi Arabia) | Al-Noaimi, Khalid R. (EXPEC-Advanced Research Center, Saudi Aramco, Dhahran 31311, Saudi Arabia) | Al-Muntasheri, Ghaithan A. (EXPEC-Advanced Research Center, Saudi Aramco, Dhahran 31311, Saudi Arabia)
Abstract Proppant selection and placement have been significantly discussed in the literature as the key parameters to measure the success of a hydraulic fracturing treatment. Conventional proppant pack may suffer a significant reduction in conductivity due to gel damage, fines migration, multiphase flow, and non-Darcy flow. To mitigate these adverse effects, an alternative posits to substitute the porous proppant pack in the fracture with an isolated structure made of propped pillars surrounded by a network of open channels. However, recent field data has not shown improvement in the productivity of the well due to channel creation within the fracture geometry. The objective of this study is to understand the effect of proppant permeability, placement, and channel creation on the well productivity using the numerical technique. A 3D numerical model was constructed to simulate the hydrocarbon flow from the reservoir through the fracture towards the wellbore. Production rate, well productivity index (PI), and dimensionless well productivity index (Jd) were evaluated as a function of the following parameters: -Reservoir effective permeability (0.1–1000 mD), -Vertical to horizontal permeability ratio (0.1-1), -Reservoir drawdown pressure (500-5000 psi), -Proppant conductivity in the near wellbore region (1–5000 mD-ft), -Proppant conductivity in the far-field region (1–5000 mD-ft), -No. of the created channels and their distribution. For conventional proppant pack, numerical results agreed with Cinco-Ley and Samaniego-V (1981), and it showed that dimensionless fracture conductivity (CFD) values higher than 30 maximize Jd. Also, the numerical model revealed that pillar fracturing technology with highly conductive channels could significantly improve well productivity if the used proppant conductivity is low. However, for high proppant conductivity and high CFD values, the maximum increase in well productivity index due to channel creation will be only 20%. For low CFD values, pillar fracturing technique with highly conductive channels is highly recommended, particularly if the vertical to horizontal permeability ratio is low. Statistical analysis of the numerical results evinced that reservoir permeability and near-wellbore proppant conductivity have a major effect on the well productivity; whereas proppant conductivity in the far-field region has limited effect. The statistical analysis revealed that any number of channels greater than 2 has marginal influence on the well productivity and that the derived, dimensionless, variables can be used to create conditional decision models to maximize it. The results suggest that there is an interplay between the dimensionless fracture conductivity and the near-to-far-field permeability ratio that has a significant influence on the results.
- Europe (1.00)
- North America > United States > Texas (0.95)
- Asia > Middle East > Saudi Arabia (0.68)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
Enhancing Oil Recovery - Advanced Simulations for More Accurate Frac-Stages Placement
Saad, Bilal (Baker Hughes) | Negara, Ardiansyah (Baker Hughes) | Hussain, Maaruf (Baker Hughes) | Elgassier, Mokhtar (Baker Hughes) | Sun, Shuyu (University of Science and Technology) | Abdullah, King (University of Science and Technology)
Abstract Hydraulic fracture stimulation designs are typically made of multiple stages placed along the lateral section of the well using various well completion technologies. Understanding how multiple hydraulic fractures propagate and interact with each other is essential for an effective stimulation design. The number and placement of stages are important factors for optimizing the performance of the laterals. This in turn depends on accuracy in determining fracture interference. We present advanced simulations for accurate placement of well stages. In this paper, we use a 3-D fully coupled geomechanical-fluid flow simulator which incorporates anisotropic geomechanical properties. Densely complex natural fractures and lamination are built into the model based on available core and log information. Multiple fractures are concurrently imployed to simulate real life scenarios. Fluid pressures are incrementally computed such that stress state changes dynamically with time as it happens in real field situation. Our simulations were run on Cray XC 40 HPC system. The results demonstrate that the stress shadow effects can significantly alter hydraulic fracture propagation behavior, which eventually affects the final fracture geometry. The results show that there are large differences in aperture throughout the stimulation which persists to the end of pumping. Furthermore comparison between cases with and without complex natural fractures (discrete fracture network (DFN)) and lamination was conducted with even and uneven spacing configurations. Fracture interference and spacing analysis conducted based on model with perforation frictions shows that while spacing between fractures is important, the largest impact was observed in the presence of lamination and DFN. The large differences in the way the fracture propagates highly depend on the DFN connectivity. Late-stage connection throughout the model implies later disconnection when the pressure drops. Though the computations are time intensive, we believe this is a valuable tool to use in the planning stages for asset development to increase production potential.
- Asia > Middle East (0.93)
- Europe (0.68)
- North America > Canada > Alberta (0.28)
- (2 more...)
- Research Report > New Finding (0.69)
- Research Report > Experimental Study (0.54)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)