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Results
Abstract Conventional in-situ upgrading techniques use electric heaters to heat oil shale. However, the efficiency of electrical heating method is very slow which requires preheating more than a year. Most conventional heating technologies focused on converting the oil shale, not shale oil reservoirs. The shale oil matrix is very tight and the pore scale is in micro to nano-meter. In this paper, it has been attempted to inject air into hydraulically fractured horizontal wells to create in-situ combustion of shale oil in ultra-low permeability formations. Heat is introduced into the formation through multistage fractured horizontal wells, which enhances the contact area of exposed kerogen. The main focus of this paper is to evaluate the technical feasibility of recovering shale oil resources by air injection. It involves the application of hydraulic fracturing technology to enhance the kerogen exposure to oxygen. Heat flows from the fracture into shale oil formation, gradually converting the solid kerogen into mobile oil and gas, which can be produced via fractures to the production wells.
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Lucaogou Formation (0.99)
- Asia > Russia > West Siberian Basin > Bazhenov Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 9/28a > Crawford Field (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Sizing Gelant Treatment for Conformance Control in Hydraulically-Fractured Horizontal Wells
Liang, Bin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Jiang, Hanqiao (China University of Petroleum, Beijing) | Li, Junjian (China University of Petroleum, Beijing) | Li, Min (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lan, Yuzheng (University of Texas at Austin) | Seright, Randall (New Mexico Petroleum Recovery Research Center)
Abstract Horizontal wells are subject to water breakthrough problems caused by natural or hydraulic fracture connections. Treatment with gelant normally is an effective choice. However, at present, no methods can provide quantitative guidance for designing gelant treatment in fractured horizontal wells. In this paper, we proposed a fracture-conductivity-based analytical model to guide sizing gelant treatment in hydraulically fractured horizontal wells. It includes the evaluation of fracture number intersected with the horizontal well, calculation of gelant leakoff distance according to the desired water productivity reduction, and the method to determine optimal gelant volume. The principle for controlling gelant injection and the method for forecasting water shutoff performance are also included. The successful application is based on two requirements: (1) gelant can penetrate a short distance from fracture surface into adjacent matrices; and (2) gelant or gel can reduce permeability to water more than to hydrocarbon. Finally, we summarize a 9-step procedure for sizing gelant treatment in fractured horizontal wells. This work provides quantitative guidance for water shutoff treatment using cross-linked polymer gels that create disproportionate permeability reduction.
- 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)
- (23 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract Reservoir simulators often predict poor injectivity in polymer enhanced oil recovery (EOR) projects because of the high polymer viscosity, which is a deterrent for the project. However, field studies have shown much higher injectivity than predicted by the models. The objective of this work is to perform grain-scale, coupled fluid dynamics and geomechanics modeling to predict the injectivity of viscous, non-Newtonian polymers in wellbores. Fluid-rock interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Fluid flow is determined using an open-source CFD software that solves the volume-averaged Navier-Stokes equation using the finite volume method on Eulerian grids. Grain-scale geomechanics (DEM) is used to explicitly solve the particle trajectories in a Lagrangian reference system. The simulation results confirm the hypothesis of fracture initiation and sand failure near the injector. The results show that the polymer-driven fracture initiation is associated with sand shear failure, while the fracture geometry is the result of the localization of sand shear failure and fluidization of unconsolidated sand at the fracture tip. The injection of a viscous fluid can create fractures in the direction perpendicular to the applied minimum principal stress. The presence of fractures increases the injectivity. The peak injection pressure is more than 3 times greater than the applied minimum principal stress. The viscosity increase of polymers promotes the initiation of fractures and results in a greater fracture aperture. The injection of polymer can promote the initiation of fractures, and therefore, increase the polymer injectivity. This work, for the first time, uses a grain-scale model to predict polymer-driven fracture initiation and demonstrates the improved injectivity observed in the field.
- North America > United States > Texas (0.94)
- Asia (0.68)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.68)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Information Technology > Modeling & Simulation (0.48)
- Information Technology > Software (0.48)
Case Studies: Pressure-Transient Analysis for Water Injector with the Influence of Waterflood-Induced Fractures in Tight Reservoir
Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Abstract Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors. The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot. Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
- North America > United States > Texas (1.00)
- Asia > China (1.00)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.72)
- 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)
- (31 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)