**Optimizing Hydraulic Fracturing Treatment Integrating Geomechanical Analysis and Reservoir Simulation for a Fractured Tight Gas Reservoir, Tarim Basin, China**

Feng Gui, Khalil Rahman, Daniel Moos, George Vassilellis, Chao Li, Qing Liu, Fuxiang Zhang, Jianxin Peng, Xuefang Yuan and Guoqing Zou

Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/56384

**Abstract**

A comprehensive geomechanical study was carried out to optimize stimulation for a frac‐ tured tight gas reservoir in the northwest Tarim Basin. Conventional gel fracturing and acid‐ izing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stim‐ ulation of natural fractures by shear slippage, creating a conductive, complex fracture net‐ work. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States.

A field-scale geomechanical model was built using core, well log, drilling data and experien‐ ces characterizing the in-situ stress, pore pressure and rock mechanical properties in both overburden and reservoir sections. Borehole image data collected in three offset wells were used to characterize the in-situ natural fracture system in the reservoir. The pressure re‐ quired to stimulate the natural fracture systems by shear slippage in the current stress field was predicted. The injection of low-viscosity slickwater was simulated and the resulting shape of the stimulated reservoir volume was predicted using a dual-porosity, dual-permea‐ bility finite-difference flow simulator with anisotropic, pressure-sensitive reservoir proper‐ ties. A hydraulic fracturing design and evaluation simulator was used to model the geometry and conductivity of the principal hydraulic fracture filled with proppant. Fracture growth in the presence of the lithology-based stress contrast and rock properties was com‐ puted, taking into account leakage of the injected fluid into the stimulated reservoir volume

© 2013 Gui et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2013 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

predicted previously by reservoir simulation. It was found that four-stage fracturing was necessary to cover the entire reservoir thickness. Post-stimulation gas production was then predicted using the geometry and conductivity of the four propped fractures and the en‐ hanced permeability in the simulated volume due to shear slippage of natural fractures, us‐ ing a dual-porosity, dual-permeability reservoir simulator.

horizontal stress anisotropy are low, because these combinations of stress and natural fractures allow fractures in multiple orientations to be stimulated [3]. The result of stimulation therefore depends both on the geometry of the pre-existing fracture systems and on the in-situ stress state. It is now generally accepted that stimulation in shale gas reservoirs occurs through a combination of shear slip and opening of pre-existing (closed) fractures and the creation of new hydraulic (tensile) fractures [4-6]. In wells that are drilled along the minimum horizontal stress (Shmin) direction, stimulation generally creates a primary radial hydraulic fracture that is perpendicular to Shmin. Then, pressure changes caused by fluid diffusion into the surrounding rock and the modified near-fracture stress field induced by fracture opening cause shear slip on pre-existing natural fractures. If the horizontal stress difference is small enough, new hydraulic fractures perpendicular to the main fracture can open. Each slip or oblique opening event radiates seismic energy, which, if the event is large enough, can be detected using

Optimizing Hydraulic Fracturing Treatment Integrating Geomechanical Analysis and Reservoir Simulation for…

http://dx.doi.org/10.5772/56384

1017

Founded on the idea that productivity enhancement due to stimulation results not just from creation of new hydraulic fractures but also from the effect of the stimulation on pre-existing fractures (joints and small faults), a new workflow dubbed "shale engineering", was estab‐ lished by combining surface and downhole seismic, petro-physical, microseismic, stimulation, and production data [7, 8]. In this new workflow (Figure 1), the change in flow properties of natural fractures is predicted using a comprehensive geomechanical model based on the concept of critically stressed fractures [9-11]. Existing reservoir simulation tools can then be used to model the hysteresis of fracture flow properties that result from the microseismically detectable shear slip, which is critical to the permanent enhancement in flow properties and increased access to the reservoir that results from stimulation. The primary hydraulic fracture created and propped during the stimulation can be modeled using conventional commercial hydraulic fracture models by taking into account fluid leaked into natural fractures in the surrounding region. The propped conductivity is estimated using laboratory-based proppant conductivity data adjusted for the proppant concentration in the fracture. The propped main fracture model and the reservoir model with stimulated natural fracture properties can then be integrated into production simulators to predict production after the slickwater hydraulic fracturing treatment. When available, microseismic data can be used to help define the network

of stimulated natural fractures that comprises the stimulated reservoir volume (SRV).

Although this new workflow was developed based on experiences in shale gas reservoirs, we believe it can also be applied to any unconventional reservoir requiring stimulation that has pre-existing natural fractures. Both Coal Bed Methane (CBM) and fractured tight gas reservoirs are examples of where this approach could be applied. In this paper, we will illustrate the workflow using the results of a study conducted in a fractured tight gas reservoir in the Kuqa

The project discussed in this paper was initiated to investigate various methods and practices to improve the economics of the field. Conventional gel fracturing had been tested in a few

downhole or surface geophones.

Depression, Tarim Basin.

**2. Project background**

For the purpose of comparison, a conventional gel fracturing treatment was also designed for the same well. It was found that two-stage gel fracturing was sufficient to cover the whole reservoir thickness. The gas production profile including these two propped fractures was also estimated using the reservoir simulator.

The modeling comparison shows that the average gas flow rate after slickwater or low-vis‐ cosity treatment could be as much as three times greater than the rate after gel fracturing. It was therefore decided to conduct the slickwater treatment in the well. Due to some opera‐ tional complexities, the full stage 1 slickwater treatment could not be executed in the bottom zone and treatments in the other three zones have not been completed. However, the posttreatment production test results are very promising. The lessons learned in the planning, design, execution and production stages are expected to be a valuable guide for future treat‐ ments in the same field and elsewhere.
