Summary
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.
Introduction
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.
© 2009. Society of Petroleum Engineers
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History
- Original manuscript received:
19 November 2007
- Meeting paper published:
13 February 2008
- Revised manuscript received:
19 October 2008
- Manuscript approved:
22 November 2008
- Published online:
1 May 2009
- Version of record:
1 May 2009
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