Summary
The Barnett shale is an unconventional gas reservoir that currently extends
over an estimated 54,000 sq miles. In an effort to improve well economics and
to reduce the number of surface locations in populated areas, the number of
wells being drilled and completed has rapidly increased. With this change in
development strategy, operators and service companies alike have had to search
for innovative solutions to overcome challenges faced in horizontal
completions.
Inefficient fracture initiation is the largest reoccurring problem
encountered when completing horizontal Barnett shale wells. These difficulties
have manifested themselves as high-fracture initiation and propagation
pressures, which lead to low injection rates and high treating pressures. These
losses reduce the efficiency of proppant placement and stimulation. As drilling
activity has increased over the past couple of years, fracture-initiation
problems are now a substantial source of expense and downtime.
This field study examines 256 horizontal Barnett shale wells in an effort to
identify the causes of these near-wellbore issues and to offer corrective
solutions for future completions. The goal of this study is to recommend an
optimized completion strategy to minimize these near-wellbore problems,
increase stimulation coverage, and decrease unplanned completion expenses.
In 2005, 19% of the stages in horizontal wells examined encountered
near-wellbore difficulties. This field study inspects the major contributors to
fracture initiation, specifically focusing on cemented vs. uncemented laterals,
horizontal-stress anisotropy, perforation strategy, cementing strategy, and
stimulation design.
The paper offers statistics on which changes have had the greatest effect on
stimulation placement. These problems can cost operators an additional 25% per
stage or more. Using these optimized strategies has reduced by 74% the number
of stages in which fracture-initiation difficulties have been encountered.
Introduction
The Barnett shale is a Mississippian marine shelf deposit that lies
unconformably on the Ordovician Viola limestone/Ellenburger group and is
overlain conformably by the Pennsylvanian Marble Falls limestone. The Barnett
shale is within the Forth Worth basin, and the focus of our study will
concentrate on wells within Denton, Wise, and Tarrant counties, which form the
core area. The Barnett in the core area ranges from 300 to 500 ft in thickness.
Permeabilities range from 0.00007 to 0.0005 md with porosities that range from
3 to 5%. The Barnett shale is believed to be its own source rock and is
abnormally pressured in this area. Commercial production is achieved only with
hydraulic-fracture treatments.
Before 1997, Barnett shale wells were completed with massive
hydraulic-fracture treatments consisting of crosslinked gelled fluids and large
amounts of proppant. Because of difficulties with effectively cleaning up
fracture damage caused by the crosslinked gel and the high cost of these
massive stimulation treatments, the wells were not as economical as desired. In
1997, large-volume, high-rate slickwater fracture-stimulation treatments were
sought as a less-expensive alternative. Although well performance was not
increased drastically with slickwater, completion costs were reduced by
approximately 65%. In 2002, horizontal wells were experimented with in an
effort to increase the wellbore's exposure to the reservoir. The results of the
first horizontal wells compared to vertical wells were three times the
estimated ultimate recovery at twice the well cost. Horizontal wells offered an
economic solution to areas outside the core and reduced the number of surface
locations needed near populated areas.
In the early stages of horizontal completions, the wells were divided
equally between uncemented and cemented laterals. Shorter laterals that
required single stimulations were uncemented, and cemented laterals were
implemented when the stimulation design required multiple stages because of an
increased lateral length. Composite bridge plugs were used for stage isolation.
Fractures in uncemented laterals are prone to grow in such a way that
unstimulated volumes, or "gaps," are often left in the reservoir; this
can equate to a smaller overall fracture area and reduced productivity (Fisher
2004), as illustrated in Fig. 1.
As drilling progressed outside the core area and acreage became more readily
available to accommodate longer laterals, the number of cemented horizontals
surpassed the number of uncemented horizontals. However, the increase in
cemented laterals also yielded a higher rate of inefficient fracture initiation
than that seen in uncemented laterals. In 2005, more than one in four cemented
horizontals experienced fracture-initiation problems, as compared to one in 25
for uncemented laterals (Fig. 2). This overwhelming rate led to the optimized
completion strategy offered in this paper.
Inefficient fracture initiation can be defined as the lack of sufficient
fluid-injection rates that results in the inability to pump designed proppant
concentrations, delivering an ineffective fracture network. The stimulation job
typically will be characterized by high pumping pressures and, occasionally,
abnormal fracture gradients. Fig. 3 displays an example of an inefficient
fracture initiation, while Fig. 4 displays an efficient fracture initiation and
propagation.
Inefficient fracture initiation can be related to cement design, perforation
phasing, perforating lengths, cluster spacing, formation stresses, and
hydraulic-fracture pad-stage design. The cost incurred because of these
problems is quite significant, representing an additional 25% of a stage's
total completion cost. The cost of an improperly placed stage also can be
detrimental to the productivity of the well by reducing the overall fracture
area. Each failure also provides a logistical problem by setting the fracturing
schedule back a day or more, thereby reducing the efficiency of the completion
program. The goal of this case study was to recommend an optimized completion
strategy that would reduce the completion cost of cemented horizontals,
increase stimulation coverage, and accommodate an aggressive drilling program's
need to maintain an undisturbed fracturing schedule.
The case study was divided into two distinct segments. First is the
problem-assessment segment, which evaluated 154 horizontal wells, 31 of which
displayed inefficient-fracture-initiation issues. Correlations were developed
by use of field data to recognize probable causes and possible solutions to
overcome these challenges. The second segment included 102 horizontals in which
these new strategies were implemented. This paper will discuss how
fracture-initiation problems were reduced to 4.7% from 19.1, a 74%
improvement.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
7 July 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
6 March 2008
- Manuscript approved:
12 March 2008
- Version of record:
15 August 2008
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