Fiber-Based Fracture Fluid Technology a First for Oil Reservoirs in Western Siberia

Abstract

Abstract Successful hydraulic fracturing in various "risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin, as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This can be achieved using low-viscosity fluids, such as viscoelastic systems, oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enhances fracture placement success. As the treatments significantly differ from the regular fiber assisted application in tight gas formations, a series of experiments had to be performed to ensure full compatibility with formation fluid, resin-coated proppants, and treating fluids. Characteristics such as leakoff behavior, viscosity development, settling rate for large-sized proppants, and fiber degradation in static and dynamic conditions were determined in various laboratory tests. This engineering work allowed fiber based fluids technology to be extended to moderate permeable oil reservoirs (1–20 md) and relatively cool formations (76-95ºC), where fracturing treatments are regularly designed for tip-screenout treatments requiring fracture geometry control maximizing proppant pack permeability by increasing mesh size and proppant concentration. The first five treatments performed have pushed the limits of the technology in regard to proppant size, type, concentration, and fracture fluid gel loading. Combining this solution with the use of advanced HGC materials offers unprecedented results in regard to fracture-height containment, where positive net pressures were obtained the first time. These operational results were confirmed by production measurements where the average water cut is 50% lower compared to the conventional treatments. Increases in productivity allowed up to a 37% increase in oil flow rate. Introduction Initially the technology has been developed as fiber assisted transport system to reduce proppant settling time in low viscosity fluids1–3. Tight gas formations in North America were the prime target application for this novel technology where low concentration and small mesh size proppant fracture treatments are typically pumped. These fracture treatments are carried out with low polymer concentration, non-crosslinked fracturing fluids, regularly in order of 1.7–3.0 kg/m3 (15–25 lbs/1000gal). Fiber addition improves the proppant carrying properties that these low viscosity fluid lack. The low viscosity fluids are also allowing for lower net pressure rate increase resulting in the possibility to place fractures with longer fracture half lengths and reduced fracture heights improving the possibility to contain the fracture in the pay zone This proved to be beneficial particularly in reservoir conditions where fracture vertical extension barriers are weak or non-existent and the underlying zone is water saturated. In addition the fibers allow for better proppant distribution throughout the hydraulic fracture. The better final proppant distribution is a result of the proppant suspension properties of the fibers that physically prevent the proppant gravitational separation and hold the proppant particles in place while the fracture faces are closing on the proppant. This property will prove extremely important in conditions where fracturing fluid leak-off is very low leading to long fracture closure times. These conditions are not uncommon in low permeability and highly laminated reservoirs.