Optimization of the Horizontal-Well Hydraulic-Fracture Geometry From Caprock-Integrity Point of View Using Fully Coupled 3D Cohesive Elements
- Seyed Erfan Saberhosseini (Islamic Azad University) | Hossein Mohammadrezaei (Iranian Offshore Oil Company) | Omid Saeidi (Iranian Offshore Oil Company) | Nadia Shafie Zadeh (Natural Resources Canada) | Ali Senobar (Iranian Offshore Oil Company)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2018
- Document Type
- Journal Paper
- 251 - 268
- 2018.Society of Petroleum Engineers
- Cap rock integrity, Injection rate, Hydraulic fracturing, Fracture geometry, Cohesive elements
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- 174 since 2007
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Pre-analysis of the geometry of a hydraulically induced fracture, including fracture width, length, and height, plays a crucial role in a successful hydraulic-fracturing (HF) operation. Besides the geometry of the fracture, the injection rate should be optimal for obtaining desired results such as maintaining sufficient aperture for proppant placement, avoiding screenouts or proppant bridging, and also preventing caprock-integrity failure as a result of an extensively uncontrolled fracture in reservoirs. A sophisticated numerical model derived from the cohesive-elements method has been developed and validated using field data to obtain an insight on the optimal fracture geometry and injection rate that can lead to a safe and efficient operation. The HF operation has been conducted in an oil field in the Persian Gulf with the aim of enhanced oil recovery (EOR) from a limestone reservoir with low matrix permeability in a horizontal wellbore. The concept of the cohesive-elements method with pore pressure as an additional degree of freedom has been applied to a 3D fully coupled HF model to estimate fracture geometry, specifically fracture height as a function of the optimal injection rate in a reservoir porous medium. It was observed that by increasing injection rate, all the fracture-geometry parameters steeply increased, but the fracture height must be controlled to be in the reservoir domain and not surpass the caprock and sublayer. For the reservoir under study with the maximum height of 100 m, length of 250 m, width of 100 m, permeability of 2 md, and porosity of 10%, the optimal fracture height is 73.4 m; the average fracture width and half-length are 12.8mm and 55.4 m, respectively. Therefore, the optimal injection rate derived from the fracture height and geometry is in this case 4.5 bbl/min. The computed fracture pressure (49.55 MPa = 7,283.85 psi) has been compared with the field fracture pressure (51.02 MPa = 7,500 psi), and the error obtained for these two values is 2.88%, which showed a very good agreement.
|File Size||3 MB||Number of Pages||18|
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