Summary
In many reservoirs, fracture growth may be complex because of the
interaction of the hydraulic fracture with natural fractures, fissures, and
other geologic heterogeneities. The decision whether to control or exploit
fracture complexity has significant impact on fracture design and well
performance. This paper investigates fracture-treatment-design issues as they
relate to various degrees and types of fracture complexity (i.e., complex
planar fractures and network fracture behavior), focusing on
fracture-conductivity requirements for complex fractures. The paper includes
general guidelines for treatment design when fracture growth is complex,
including criteria for the application of water-fracs, hybrid fracs, and
crosslinked fluids.
The effect of proppant distribution on gas-well performance is examined for
cases when fracture growth is complex, assuming that proppant was either
concentrated in a primary planar fracture or evenly distributed in a fracture
network. Examples are presented that show that when fracture growth is complex,
the average proppant concentration will likely be too low to materially impact
well performance if proppant is evenly distributed in the fracture network and
unpropped-fracture conductivity will control gas production.
Reservoir simulations illustrate that the network-fracture conductivity
required to maximize production is proportional to the square root of fracture
spacing, indicating that increasing fracture complexity will reduce
conductivity requirements. The reservoir simulations show that
fracture-conductivity requirements are proportional k1/2 for
small networks and k1/4 for large networks, indicating much
higher conductivity requirements for low-permeability reservoirs than would be
predicted using classical dimensionless conductivity calculations (FCD
) where conductivity requirements are proportionate to reservoir
permeability (k). The results show that when fracture growth is complex,
proppant distribution will have a significant impact on network-conductivity
requirement and well performance. If an infinite-conductivity primary fracture
can be created, network-fracture-conductivity requirements are reduced by a
factor of 10 to 100, depending on the size of the network. The decision to
exploit or control fracture complexity depends on reservoir permeability, the
degree of fracture complexity, and unpropped-fracture conductivity. It can be
beneficial to exploit fracture complexity when the permeability is on the order
of 0.0001 md by generating large fracture networks using low-viscosity fluids
(water fracs). As reservoir permeability approaches 0.01 md, fluid efficiency
decreases, and fracture-conductivity requirements increase, fracture designs
can be tailored to generate small networks with improved conductivity using
medium-viscosity or multiple fluids (hybrid fracs). Fracture complexity should
be controlled using high-viscosity fluids, and fracture conductivity should be
optimized for moderate-permeability reservoirs, on the order of 1 md.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
3 July 2008
- Meeting paper published:
22 September 2010
- Revised manuscript received:
16 June 2010
- Manuscript approved:
29 June 2010
- Published online:
24 September 2010
- Version of record:
17 November 2010
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