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ABSTRACT: The diagnostic fracture injection test based on the response of bottomhole pressure to fracture state is widely applied to estimate the reservoir parameters, in which closure pressure can be effectively identified. In this paper, A 2D fluid-solid coupling model using the cohesive zone method is built to simulate the fracture injection test, and the effect of rock mechanical property, in-situ stress and angle between fracture and primary stress on the fracture closure pressure is discussed. The results reveal that the minimum principal stress is the main influencing factor, in addition, as the elastic modulus and tensile strength increase, the closure pressure increases. When there is an angle between the fracture and the maximum horizontal principal stress, it should be noted that the closure stress value increases. The simulation results can provide the guidance for the calculate of closure pressure in the diagnostic fracture injection test.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
Numerical Analysis of Complex Fracture Propagation Under Temporary Plugging Condition in Natural Fractured Reservoir
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90ยฐ, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30ยฐ or larger than 150ยฐ can be open, and the outcome will be opposite if the approaching angle is larger than 45ยฐ or less than 135ยฐ. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
- North America > United States (1.00)
- Asia > Middle East > Jordan (0.24)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- Europe > Netherlands > German Basin (0.99)
- Europe > Germany > German Basin (0.99)
- (2 more...)
Study on the Natural Fractureโs Effect on Hydraulic Crackโs Propagation in Coal Seam
Song, Chenpeng (State Key Laboratory of Coal Mine Disaster Dynamics and Control) | Lu, Yiyu (State Key Laboratory of Coal Mine Disaster Dynamics and Control) | Jia, Yunzhong (State Key Laboratory of Coal Mine Disaster Dynamics and Control)
Abstract To investigate the natural fracture's effect on hydraulic fracturing crack propagation in the coal seam, the two-dimensional model of hydraulic fracturing crack intersecting natural fractures is built. Based on it, the laws of crack propagation and failure mechanism of natural fractures are studied by using the method of theoretical analysis and numerical simulation. The research suggests that angle of interaction between main crack and natural fracture, the horizontal differential principal stress and the development degree of natural fractures are the three main factors that affect direction of crack propagation. The direction of the propagation of crack tends along natural fracture due to shear failure in condition of low horizontal differential principal stress and low angle of interaction; Besides, with the increase of horizontal differential principal stress or angle of interaction, the propagating fracture tends to cross the natural fracture. The small size of natural fracture had little or no effect on the direction of the propagation of hydraulic fracture whereas the propagating fracture turns to natural fracture's direction when the size of natural fracture is large.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Small volume hydraulic fracture tests, defined as microfrac tests, are conducted to determine the in situ principal stresses in oil formations. Interpretation difficulties arise when the tests are conducted in relatively shallow, unconsolidated sands which are typical of the oil sand deposits in Alberta, Canada. Interpretation methods for such tests are outlined and their use is discussed. Three microfrac case histories in the Athabasca oil sands deposit are presented and analyzed. Recommendations are given for performing microfrac tests in these formations. performing microfrac tests in these formations Introduction The past fifteen years have witnessed the progressive development of the large progressive development of the large hydrocarbon reserves, 1350 ร 10 to the 9th bbl (214 ร 10 to the 9th m), located in the oil sands deposits of Alberta. Two major surface mining operations are currently in operation in the Athabasca deposit, but less than 10% of the area is shallow enough to allow surface mining operations. Therefore, other recovery strategies are being investigated or used for the remaining oil sands. Esso Resources is operating a full scale in situ production project in the Cold Lake deposit production project in the Cold Lake deposit involving steam stimulation techniques. Due to high bitumen viscosities (e.g. 3 ร 10 to the 6th cp (3.0 ร 10 to the 3rd Pa.s)) under reservoir conditions, the bitumen will not readily flow through the sand matrix. Thermal methods, such as cyclic steam stimulation and steam flooding, are used to improve the bitumen mobility. In the most common technique, cyclic steam stimulation, the payzone is fractured to improve the areal payzone is fractured to improve the areal conformance of the steam. Field performance and research have shown that the in situ stress state is the first order control on hydraulic fracture behaviour. For oil sands, shear failure may occur prior to tensile fracturing depending on the relationship between the in situ stresses and the formation pore pressure. Rational design of well patterns, pore pressure. Rational design of well patterns, spacing, and operating procedures requires knowledge of the in situ stresses along with geomechanical properties of the oil sands. The small volume hydraulic fracture test, the microfrac test, is the only method available for measuring in situ stress at reservoir depth. Although hydraulic fracturing stress measurements have been practiced for many years, it has only been recently that the test method has been standardized. Furthermore, the analysis of hydraulic fracturing tests for determining in situ stresses remains the subject of varying interpretation as shown by the papers of the 1988 International Workshops on Hydraulic Fracturing Stress Measurements. P. 243
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.98)
Abstract: In field data from multiple stage hydraulic fracturing treatments of five horizontal wells in the Barnett Shale, the Initial Shut-in Pressure (ISIP) tended to increase along the wellbore as the stimulation of each well progressed. The increasing trend was less prominent in wells where there was greater shut-in time between stages. We investigated these trends using (1) a hydraulic fracturing simulator that couples fluid flow and fracture deformation in discrete fracture network models and (2) a simple expression derived from the scaling of induced stresses with distance. Based on the scaling relationship, we found that if stress shadowing alone caused the increasing trend in ISIP, then ISIP should have approximately plateaued after a few stages. In contrast to this prediction, ISIP in three of the wells escalated across the entire lateral. We conclude that stress shadowing alone cannot account for these trends. In a simulation performed with the hydraulic fracturing model, stress shadow and bottom hole pressure dropped over time after shut-in despite the fact that fluid leakoff into the matrix was not included in the simulation. The weakening of stress shadow occurred because of time-dependent spreading of fluid into a larger number of more spatially dispersed, open fractures.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.61)