Hannes Hofmann

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and hot-dry-rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in biwing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial discrete fracture network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulations suggest that stress state, in situ fracture networks, and fluid type are the main parameters influencing hydraulic fracture network development. Major factors leading to more complex fracture networks are an extensive pre-existing natural fracture network, small fracture spacings, low differences between the principle stresses, well contained formations, high tensile strength, high Young’s modulus, low viscosity fracturing fluid, and large fluid volumes. The differences between 5 km deep granitic HDR and 2.5 km deep shale gas stimulations are the following: (1) the reservoir temperature in granites is higher, (2) the pressures and stresses in granites are higher, (3) surface treatment pressures in granites are higher, (4) the fluid leak-off in granites is less, and (5) the mechanical parameters tensile strength and Young’s modulus of granites are usually higher than those of shales.

Evaluating Micro-Seismic Events Triggered by Reservoir Operations at the Geothermal Site of Groß Schönebeck (Germany)

This study aims at evaluating the spatial and temporal distribution of 26 micro-seismic events which were triggered by hydraulic stimulation at the geothermal site of Groß Schönebeck (Germany). For this purpose, the alteration of the in-situ stress state and the related change of slip tendency for existing fault zones due to stimulation treatments and reservoir operations is numerical simulated. Changes in slip tendency can potentially lead to reactivation of fault zones, the related movement can lead to the occurrence of seismic events. In the current numerical study, results obtained based on the thermal–hydraulic–mechanical coupled simulation are compared to field observations. In particular, the study focuses on describing the fault reactivation potential: (1) under in-situ stress conditions; (2) during a waterfrac stimulation treatment; and (3) during a projected 30 years production and injection period at the in-situ geothermal test-site Groß Schönebeck. The in-situ stress state indicates no potential for fault reactivation. During a waterfrac stimulation treatment, micro-seismic events were recorded. Our current evaluation shows an increase of slip tendency during the treatment above the failure level in the direct vicinity of the micro-seismic events. During the projected production and injection period, despite increased thermal stress, the values for slip tendency are below the threshold for fault reactivation. Based on these results, and to prove the applied method to evaluate the observed micro-seismic events, a final discussion is opened. This includes the in-situ stress state, the role of pre-existing fault zones, the adopted criterion for fault reactivation, and a 3D rock failure criterion based on true triaxial measurements.