Optimization of the Horizontal-Well Hydraulic-Fracture Geometry From Caprock-Integrity Point of View Using Fully Coupled 3D Cohesive Elements

Abstract

Summary 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 12.8 mm 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.

A simulation study of hydraulic fracturing design in carbonate reservoirs: a middle east oilfield case study

“…At present, many papers have present field applications using the integrated geologic and engineering approach for hydraulic fracturing modeling and production forecast in unconventional oil and gas reservoirs, but mainly for tight sandstone and shale formations Saberhosseini et al 2017;Vishkai and Gates 2019;Wang et al 2019;Yong et al 2021;Lu et al 2022a and2022b). In this paper, this method is applied to the hydraulic fracturing design for a carbonate reservoir in Middle East.…”