The solid-free viscoelastic surfactant (VES) fluid has good proppant transport and excellent cleanup capabilities. Coupling the benefits of a VES fluid with a carbon dioxide (CO 2 )-emulsified system will further enhance cleanup in a depleted reservoir, extend the application to water-sensitive formations, and maintain reservoir gas saturation to prevent any potential water blocks. This paper reports on a new multisurfactant VES fluid system developed specifically to provide a robust surfactant-base fracturing fluid with supercritical CO 2 . The field test results indicate the new system is CO 2 compatible and still possesses all the attributes normally associated with VES systems.

Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity. Pre-existing faults were identified by edge detection/ant tracking algorithms applied to seismic reflection data, as well as from advanced analysis of the microseismicity, including microseismic deformation levels, magnitude-frequency characteristics and composite failure mechanism analysis. In cases where the wells were far from pre-existing faults simple, planar hydraulic fractures were observed, although there was a tendency to grow towards regions of low Poisson's ratio based on amplitude versus offset inversion of the seismic reflection data. The tendency for the hydraulic fractures to be asymmetric and grow preferentially towards the low Poisson's ratio region is attributed to material property changes and associated lower stresses in these regions. Insight from the enhanced reservoir characterization with integrated microseismic and treatment data is being used for better well placement, improved completion designs and increased production.

In the past decade the industry has embraced unconventional resources; namely, shale oil and shale gas. After the initial drill-to-hold stage, multiwell pad drilling and stimulations are employed to exploit the acreage. Zipper fracturing is a technique that reduces the standby time (up to 50% reduction, when combined with the plug-and-perf isolation method). Because of this operational efficiency improvement, zipper fracturing has become one of the most common fracturing practices for unconventional reservoir stimulation. It has also been purported to increase production, which several authors have previously reported. There are also other studies showing no benefit of zipper fracturing on production performance.In this paper we have used a complex fracture network model, which we refer to as the Unconventional Fracture Model (UFM), to study zipper fracturing. The model simulates complex (branched) fracture propagation, associated stress shadows, fluid flow, and proppant transportation in the complex fracture network. The model solves the fully coupled problem of fluid flow in the fracture network and elastic deformation of the fracture. A key difference between UFM and the conventional planar fracture model is being able to simulate the interaction of hydraulic fractures with preexisting natural fractures (also referred as planes of weakness). The UFM simulates interwell and interstage stress shadows and honors both sequential fracturing and zipper fracturing scenarios' geomechanical interaction.In this paper, we present the results of a zipper and sequential fracturing study that includes the completion design optimization and the associated production performance in the Eagle Ford Shale. The study provides a workflow to optimize the completion and stimulation designs in pad development and to improve rate of return. The quantitative results show that zipper fracturing may not deliver a production benefit when compared with sequential fracturing and is a function of well spacing and perforation cluster spacing in a given area.

Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity. The increased level of microseismic deformation and corresponding fault-related source characteristics correlated with the presence of a pre-existing fault identified by edge detection/ant tracking algorithms applied to seismic reflection data. In cases where the wells were far from pre-existing faults simple, planar hydraulic fractures were observed, although there was a tendency to grow towards regions of low Poisson's ratio based on amplitude versus offset inversion of the seismic reflection data. The tendency for the hydraulic fractures to be asymmetric and grow preferentially towards the low Poisson's ratio region is attributed to material property changes and associated lower stresses in these regions. Integrating microseismic interpretations and fracture treatment data with enhanced reservoir characterization has been used to rethink well placement and completion designs, resulting in improved well performance.

No abstract