Marc Jean Thiercelin

Characterization of Hydraulically-Induced Fracture Network Using Treatment and Microseismic Data in a Tight-Gas Sand Formation: A Geomechanical Approach

Large amount of gas are being produced from unconventional tight-gas sand reservoirs (e.g., Cotton Valley Fm., Lobo Fm., Taylor Sand Fm. and, Wilcox Fm., etc.) and shale gas-bearing formations (e.g, Barnett, Fayetteville, Marcellus, Woodford, etc.). These plays are partly technology driven and partly economics driven. Modern well log evaluation techniques and completion methods are required to yield economic wells. In some cases microseismic monitoring campaigns are performed in these various low permeability environments to improve the understanding of the induced fracture network and to go beyond the simple assumption of a symmetric bi-wing fracture system. To better characterize the induced fracture network, a semi-analytical pseudo 3-D geomechanical model was developed based on considerations of the conservation of injected fluid mass and the mechanic interactions both between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically-equivalent description of the process of hydraulic fracture propagation and the characteristics of the induced fractures. Using microseismic datasets obtained during hydraulic treatments in several tight formations together with measured wellbore pressure and treatment parameters as the input, the modeling analysis yields information of the induced fracture network including fracture spacing and associated confining stress contrast. The results indicate a vertically contained developping fracture network with anisotropic spacing and moderate confining stress contrast. The fracture network extension toward the maximum horizontal stress is however limited. This information is then used as the input of the model to carry out forward simulations and provide detailed information of time-dependent fracture propagation including front location, fluid pressure, fracture width, induced porosity and permeability.

Hydraulic Fracture Propagation in a Naturally Fractured Reservoir

This paper (SPE 128715) was accepted for presentation at the SPE Oil and Gas India Conference and Exhibition, Mumbai, India, 20–22 January 2010, and revised for publication. Original manuscript received 17 February 2010. Revised manuscript received 20 July 2010. Paper peer approved 17 August 2010. Summary We present the results of numerical modeling that quantify the physical mechanisms of mechanical activation of a natural fault because of contact with a pressurized hydraulic fracture (HF). We focus on three stages of interactions: HF approaching, contact, and subsequent infiltration of the fault. Fracture interaction at the contact is shown to depend on four dimensionless parameters: net pressure in the HF, in-situ differential stress, relative angle between the natural fault and the HF, and friction angle of the natural fault. A numerical model based on the displacement discontinuity method (DDM) allowing for fracture closure and Mohr-Coulomb friction was used to calculate the displacements and stresses along the natural fracture as a result of the interaction with the pressurized HF. The analysis of the total stress state along the fault during the HF coalescence stage makes it possible to define a criterion for reinitiation of a secondary tensile crack from the natural fault. We show that the most probable location for tensile-crack initiation is the end of the open zone of the fault where the highest tension peak is generated by the HF contact. In our numerical analysis, we study the magnitude of maximum tensile stress and its position along the fault for a wide range of key dimensionless parameters. Given real reservoir properties, these measurements can be used to detect the possible fracturing scenarios in naturally fractured reservoirs. Using simplified uncoupled modeling of fluid penetration into the fault after the contact with the HF, we demonstrate that either an increase or a decrease of the tensile stress at the opposite side of the fault can be realized depending on the ratio of increments of net pressure and the fluid front as it penetrates the natural fault.

Fracture Network Development and Proppant Placement During Slickwater Fracturing Treatment of Barnett Shale Laterals

This paper presents an application of the wiremesh hydraulic fracturing model to analyze slickwater fracturing stimulation treatments of three Barnett Shale horizontal gas wells. For each treatment stage, the created hydraulic fracture network (HFN) was characterized on the basis of associated microseismic events distribution, treatment data, and geomechanical properties of involved formation layers. A systematic analysis of all stages, such as the potential effect of earlier treatment stages on a later one, the relationship between HFN properties such as the fracture surface area and treatment parameters, etc, was also presented. The information obtained was then applied to examine proppant placement in each of the HFNs. Potential ways of treatment improvement and optimization for future jobs are discussed based on these analyses. Introduction Slickwater fracturing stimulation has been applied to many shale gas plays to enhance gas production. However better understanding of how the induced HFN grows and where proppants are placed is still needed more than ever. A new model (Xu et al. 2009a, Xu et al. 2009b, Xu et al. 2010) was developed to represent a HFN on average by an increasing stimulated shale volume consisting of two perpendicular sets of vertical planar fractures in a vertically variable and horizontal anisotropic stress field quantified by the horizontal minimum principle stress h and maximum principle stress H for each of involved formation layers (Figure 1). The size of the stimulated formation is described by the major axis a, the minor axis b and the mean height h of an expanding ellipsoid. The HFN is further characterized by its fracture spacing parameters dx and dy. Mechanical interactions among fractures and between injected fluid and fracture walls are accounted for. HFN growth is constrained by the amount and rate of fluid injection. Figure 1. Wiremesh model of complexe hydraulic fracture network illustrating (a) the expanding stimulated formation volume containing (b) the hydraulic fracture network