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Research Papers: Petroleum Engineering

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

[+] Author and Article Information
Hannes Hofmann

Department of Civil
and Environmental Engineering,
School of Mining
and Petroleum Engineering,
University of Alberta,
Edmonton, AB T6G 2W2, Canada

Tayfun Babadagli

Department of Civil
and Environmental Engineering,
School of Mining
and Petroleum Engineering
University of Alberta,
Edmonton, AB T6G 2W2, Canada

Günter Zimmermann

Helmholtz Centre Potsdam,
GFZ German Research Centre
for Geosciences,
Potsdam 14473, Germany

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received July 16, 2013; final manuscript received September 23, 2014; published online October 21, 2014. Assoc. Editor: Andrew K. Wojtanowicz.

J. Energy Resour. Technol 136(4), 042905 (Oct 21, 2014) (9 pages) Paper No: JERT-13-1211; doi: 10.1115/1.4028690 History: Received July 16, 2013; Revised September 23, 2014

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.

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Figures

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Fig. 1

Overview of the main parameters and processes involved in the hydraulic fracturing simulations (graphics taken from Refs. [1-3])

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Fig. 2

Critical stress for fracture propagation [17]

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Fig. 3

Schematic top view of the base case scenario (two fracture sets, σh = σH, and 25 m fracture spacing). The primary vertical fracture set is parallel to σH. The secondary vertical fracture set is perpendicular to the primary fracture set.

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Fig. 4

The influence of the stress variation with depth for a 2.5 km deep shale and a 5 km deep granite (1: constant stress, 2: linear stress increase, 3: stepwise stress increase, and 4: low stress formation)

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Fig. 5

Influence of the distance between injection point and the lower stress barrier on the minimum stress contrast needed for confinement and the minimum formation height (if no upper stress barrier is present)

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Fig. 6

Minimum stress contrast needed to confine fracture height growth for different fracture spacings, fracture sets, and rock types

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Fig. 7

Influence of the differences between vertical and minimum horizontal stress and between maximum and minimum horizontal stress on the minimum stress contrast required to confine fracture height growth

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Fig. 8

Influence of the fracture spacing on the maximum net pressure observed during stimulation for different rock types and fracture sets

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Fig. 9

Influence of the differences between the three principle stresses on the maximum net pressure observed during stimulation for different rock types and fracture sets

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Fig. 10

Influence of fracture spacing on the total area of the DFN for different rock types and fracture sets

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Fig. 11

Influence of the differences between the three principle stresses on the total area of the DFN for different rock types and fracture sets

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Fig. 12

Influence of the differences between the three principle stresses on the aspect ratio of the fracture system for different rock types and fracture sets

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