Fracture Impact of Yield Stress and Fracture-Face Damage on Production With a Three-Phase 2D Model
- Reza Barati (University of Kansas) | Richard D. Hutchins (Schlumberger) | Torsten Friedel (Schlumberger) | Joseph A. Ayoub (Schlumberger) | Marie-Noelle Dessinges (Schlumberger) | Kevin W. England (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2009
- Document Type
- Journal Paper
- 336 - 345
- 2009. Society of Petroleum Engineers
- 1.8 Formation Damage, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.3.4 Scale, 4.1.5 Processing Equipment, 3 Production and Well Operations, 5.5.1 Simulator Development, 4.1.2 Separation and Treating, 2.4.6 Frac and Pack, 5.1.1 Exploration, Development, Structural Geology, 1.4.3 Fines Migration, 5.8.2 Shale Gas, 5.6.4 Drillstem/Well Testing, 5.8.1 Tight Gas, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1.2 Faults and Fracture Characterisation
- simulation of fracture cleanup, yield stress, stimulation, fracture-face damage, fracture conductivity
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The fracture-propagation process performed with polymer-based fracturing fluids is applied commonly to increase the productivity of producing wells, especially in tight gas formations. The fracture-cleanup process is complex and may suffer from the presence of a yield stress, non-Newtonian fluid in place, and both mechanical and hydraulic damage to the matrix near the fracture face. A previously published fast-and-robust single-well model was applied to study the important parameters involved in the fracture-cleanup process. This three-phase 2D model proved useful for assessing the significance of reservoir capillary pressure, broken-gel viscosity, yield stress, formation damage, and fracture conductivity on low-permeability-gas-reservoir production, with studied permeabilities ranging from 0.005 to 5 md. The observed trends may not carry over to nanodarcy reservoirs, such as the gas shales. The three phases included gas, water, and fracturing gel.
Hydraulic fracturing has been used as a successful technology to increase productivity by means of significantly increased contact between the wellbore and the producing formation. To propagate an open fracture into a reservoir, fracturing fluids have been used to provide the two main functions of initiating and propagating the fracture and transporting propping agents along the fracture. Guar gum is the earliest example of an aqueous, viscous fluid used during the injection. The fracturing fluid must be viscous to allow the transport of the proppant during the injection, and it must have the ability to be broken easily after the injection to maintain high conductivity in the fracture during the production phase. To accomplish these tasks, crosslinkers (such as borates and zirconates) and delayed breakers (either oxidizers or enzymes) are added typically to the fluid (Economides and Nolte 2000).
Injection of the viscous fracturing fluid results in fluid loss to the matrix and filter-cake formation. Filter cakes with high polymer concentration form on the faces of the fracture during the injection. Original fracturing fluid may remain in the fracture unless the fracture-face filter cake occupies the entire pore space of the propped fracture following closure (Ayoub et al. 2006). Varying exposure times to fracturing fluid (Seright 2002) cause local polymer-concentration changes along the fracture. Thus, breakers are seldom distributed uniformly, and the break of the concentrated fluid is seldom complete.
At the end of a fracture treatment, there is normally a shut-in period to allow fracture closure during which fluid continues to leak off into the reservoir. Alternatively, and especially for tight gas reservoirs, the fracture can be forced to close by flowing back some of the fracturing fluid at controlled rates to prevent disturbing the proppant pack significantly. As a result, hydraulic fractures contain partially broken fracturing fluid, and residues remain after the breaker reacts with the polymer. It has been postulated that fracturing fluids need a minimum pressure gradient to begin the cleanup process in the proppant pack (May et al. 1997), and this has been verified experimentally (Ayoub et al. 2006).
The fracturing process, depending upon reservoir-matrix permeability, can cause mechanical damage through various mechanisms including fluid invasion into the reservoir, polymer-solids deposition near the fracture face as filter cake forms, clay swelling in the case of incompatible fluids, broken-polymer/fines migration into the reservoir matrix, and chemical interactions between the fracturing fluid and the matrix such as pH alteration or polymer adsorption (Holditch 1979). In addition, hydraulic damage occurs from the increase in water saturation caused by leakoff. The hydraulic damage can include a reduction in gas relative permeability and relative permeability hysteresis in the matrix where fracturing fluid has leaked off as the water saturation is first increased during leakoff and then decreased during the production phase. A shift in the capillary pressure curve to higher values can also result from mechanical damage.
The production process becomes even more complicated in tight gas formations with permeability less than 0.1 md when the combined effects of closure stress, non-Darcy flow, high capillary pressure in the matrix, and viscous fingering in the proppant pack cause additional issues and restrict the production rate.
The objectives of this study were to develop a basic understanding of the major factors impacting the fracture-cleanup process in tight gas formations with permeability of 0.005 md or greater, including yield stress of the filter cake, capillary pressure changes, and formation damage, by use of available numerical models. A three-phase, 2D model reported in the literature (Friedel 2004) was used for this study.
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