American Oil and Gas Reporter - April 2015 - 64

SpecialReport: Refrac Facts
The earliest fracs, with gelled gasoline and oils, gradually gave
way to water fracs, and as chemical additives were proven to control problems from scales to clay swelling and proppant types were
improved, wells fractured only a few years before benefited from
reapplication of advancements in technology. Refracturing of conventional wells slowed noticeably after the 1970s, but as unconventional resources took center stage and developed their specialty fracturing methods, refracs became common again.
However, as gas and oil shales slowly moved from being a
drilling nuisance to an oil and gas bonanza, operators found that
the sharp production decline common in most naturally fractured
formations could be reversed, even if only for a short time, by
refracturing the same zone.
In some shales, refracturing even produced fracture reorientation away from the initial fracture direction. For example, a
Mitchell Energy Corp. refrac program in the Barnett Shale in the
late 1990s demonstrated enhanced production from vertical Barnett gas wells as a result of refracture reorientation. This advancement of technology is driving the boom in refracturing.
Refrac Candidates

The best refrac candidate wells have several common characteristics, including sufficient remaining reserves in the well's
drainage area and large sections of the wellbore that were not accessed initially. The best candidates are in the best rock type, and
stress changes can hurt or help production and recovery rates. Good
candidates also can be wells in which initial fracture treatments
pumped small volumes, low proppant concentrations, or a damaging fluid type.
Factors that drive production decline and even low initial production may involve formation structure and the occurrence and
extent of natural fractures or large pore groups. For the specific example of naturally fractured shales, accessing the location
of the gas and oil shows along the wellbore may be one of the
more important parts of candidate selection.
Because of shale's extremely low matrix permeability, the principle flow paths are along the natural fractures. From mud logs
and other forms of monitoring gas and oil "shows", several shales
and other tight formations have demonstrated strong flow capacity in some areas along the wellbore, while other areas along the
same wellbore may have no significant hydrocarbons at all. Case
histories of locating fracture initiation points in the high-quality show areas and avoiding fracturing the areas in the wellbore
without oil or gas shows are known, but are not yet common.
Other well and formation performance factors such as laminations, faults, areas of high stress, and even frac "hits" (stimulation operations on one well interfering with one or more nearby wells at the same pay zone depth) may be part of the candidate investigation. Successful design and application of refracs
depends on finding and refining the refracture treatment.
64 THE AMERICAN OIL & GAS REPORTER

Design Elements

At first, refracs in shales were thought to only be extending
the reach of the fracture stimulation through using large volumes
of slickwater, replacing the higher-cost foam or gelled fracturing fluids. Slickwater fracturing, a low-viscosity ungelled water
fracture fluid that fell out of favor in the 1950s, was primarily
fresh- or saltwater with a small amount of friction reducer. What
intrigued many operators was that this fluid appeared to be invading and opening the closed natural fracture system, creating
complex or network fracturing and gaining at least an order of
magnitude more contact area within the reservoir.
Production improvements on refractured vertical shale wells
were often startling, since the production immediately after the
refrac equaled or was even higher than the initial production. However, sharp post-refrac production declines persisted and even a
second refrac did not temper the production decline. Obviously, the shale stimulation environment is very different from conventional reservoirs.
The answers to the complex behavior are elusive, but have their
origin in how fluids actually move in ultralow-permeability reservoirs. Depending on natural fractures as a primary flow path also
requires the natural fractures to stay open. This creates the need
for a different fracture or refracture design approach.
With the acceptance of highly deviated multifractured wells,
with roots now more than 40 years old, some in the industry believed that refracturing in shales would lose appeal since the fracturing process for shales had matured and the density of the initial fracture contact was much higher than in vertical wells.
What was perhaps not considered originally were the varied
reasons for the rapid production declines, and the uncanny resurrection of those same production levels-and declines-following a refrac. Propping narrow natural fractures may also have complications, including proppant embedment in ductile shales, high
in situ stresses that prevent the opening of extensive natural fractures, and keeping only limited proppant near the wellbore.
Keeping Fractures Propped

The initial microcracks and natural fractures in the more productive shales, although often extensive over large areas, frequently were filled with calcite and were extremely narrow (on the order of 0.002 inches when they were not calcite-filled). During a
fracture treatment, permeability in natural fractures may widen
and permeability may increase from microdarcy levels to nearly 100 millidarcies.
But if the natural fractures are not propped, fracture width will
be lost as stimulation and connate fluids are removed, and permeability-as well as the production rate-will decline sharply. The
industry has experimented with increasing levels of proppant,
mainly 100-mesh sand, and multiple companies are reporting
adding 5 million to 7 million pounds of proppant for all refracs

American Oil and Gas Reporter - April 2015

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