Perforating multiple-pay intervals to achieve optimum treatment coverage has
long been a topic of considerable debate. Perforation selection can play
a crucial role in well performance. The consequences of inadequate
perforation coverage can compromise fracture optimization, limit production,
result in missed pay, and limit reservoir access. Multizone-fracture
treatments have been performed in the past with a variety of methods ranging
from limited entry to mechanical isolation with bridge plug and packer.
These and other techniques routinely have been applied to stimulate
discrete intervals within a formation in an attempt to maximize the production
of discrete-pay zones or stringers. One method consists of perforating
and isolating each zone, then performing the stimulation treatment.
Wireline is used to isolate the previous zone and perforate the next
stage. The treatment of multiple intervals in this manner can be a costly
and time-consuming process.
A new multistage treatment process optimizes perforation and treatment
design. This technique, known as “external casing perforating” (EXCP)
allows the operator to perforate and isolate individual zones in as little as 5
minutes between treatment stages. As many as 17 discrete intervals have
been treated within a 24-hour period. Moreover, this approach minimizes
total-treatment volume by using the flush from the previous stage as the pad on
the next stage, thus placing less fluid on the formation. The time to
first sales has been reduced from days to a matter of hours by eliminating
bridge-plug isolation and costly post-job cleanup. Production from
multiple horizons may be brought online quickly in one rigless operation
without damaging and time-consuming shut-ins.
This paper describes the perforating and stimulation technique and
quantifies cost savings to the operator associated with the reduced volumes and
time saving. Additional benefits, such as reductions in friction pressure
and polymer damage, and means for fracture optimization also will be
In common practice, economic factors dictate pay selection in a given
wellbore. In multizone completions, difficult choices must be made when
determing whether to sacrifice optimum zonal coverage or to selectively isolate
and stimulate discrete-pay intervals or stringers. In the selection
process, productive intervals may be sacrificed or left behind because of
economic considerations. In some cases, these zones have gone unproduced
for years. These intervals could represent access to several hundred feet
of idle reserves.
Two such intervals were discovered in the Wilshire Devonian field in west
Texas. During fracture stimulation, it became evident that part of one
interval had substantially higher bottomhole pressure than the adjacent zones,
making it more challenging to stimulate with limited-entry techniques (Lagrone
et al. 1963). A post-job-tracer survey documented results from an attempt
at limited entry where the middle zone was left unstimulated (Fig. 1).
Previously, 3D fracture simulators indicated that the zones would fuse in a
Once an aggressive stimulation program was initiated, the higher pressures
were verified by production logs and bottomhole-pressure tests.
Bottomhole pressure, a key component in stress calculation, proved to be a key
factor in zonal isolation and effectively stimulating these
The main consideration is pay identification for optimal-treatment
coverage. In many cases, criteria for productive intervals must be
redefined on the basis of in-field test analyses and, ultimately, production.
What was once considered a nonproductive interval might prove economic in the
future, especially as petroleum pricing drives the technology necessary to
extract hard-to-reach reserves. Advances in log analysis, computer
modeling, and 3D seismic surveys have further enhanced the industry’s ability
to rapidly identify and evaluate potential pay intervals (Mendoza 1996; Davies
et al. 1994; Warpinski et al. 1995).
Operators surveyed by the Gas Research Inst. (GRI) in the mid-1990s
recognized opportunities for future improvements in production rates and cost
reduction through the use of these new technologies (Penny and Conway
1996). The initial completion on a well can have an enormous impact on
the ability to effectively access and produce the entire reservoir. After
completion, it may not be practical to reenter a wellbore to reacquire missed
pay. An optimized completion process is less costly and far more
efficient during the initial completion.
Any net gain in reserves must be weighed against completion cost. In
many cases, risk associated with the initial completion may persuade an
operator to resist technology that may provide optimum production and reservoir
access. Technology often requires some initial risk and diligence in new
applications to justify a project. The EXCP completion process is no
exception, especially because most of the cost is incurred during
drilling. Most drilling departments are driven to reduce cost and may not
realize the potential of the EXCP process to reduce final completion cost,
reduce formation damage, and increase booked reserves.
© 2006. Society of Petroleum Engineers
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- Original manuscript received:
14 February 2005
- Meeting paper published:
26 September 2004
- Manuscript approved:
8 January 2006
- Version of record:
20 November 2006