The north Texas Barnett shale illustrates the successful commercialization
of an unconventional reservoir. However, it took 17 years to evolve from
pumping crosslinked gel (XLG) carrying more than 1 million lbm of proppant per
job to sand waterfracs (SWFs) consisting of large volumes of water with
friction reducer and small quantities of sand. This transition to SWF
stimulation opened the door for widespread development that has advanced the
Newark East (Barnett shale) to the largest producing gas field in Texas.
This paper investigates Barnett completion strategy from 1993 to 2002. The
393-well data set includes completion, reservoir, and production data. Unique
data-evaluation tools and techniques were used to investigate various
completion and reservoir parameters to determine their effects on production
(Shelley and Stephenson 2000; Zangl and Hannerer 2003).
We found that production results show a broad scattering when crossplotted
with various completion and reservoir inputs. This result is not uncommon when
analyzing field data. However, general trends were identified through
comparisons of large numbers of wells. These trends were confirmed through the
use of more-advanced data-mining techniques, which included self-organizing
mapping (SOM) of data. The results show that SWF-type stimulation of the
Barnett outperformed to varying degrees XLG treatments for the five reservoir
types used in this evaluation.
The Barnett is a Mississippian marine shelf deposit. The Barnett shale
ranges in thickness from 200 ft in the southwest region to 1,000 ft in the
northeast near the Munster arch. The formation is described as a black,
organic-rich (total organic content 4.5%) shale composed of fine-grained,
nonsiliciclastic rocks with extremely low permeability (0.00007 to 0.005 md).
The organic matter in the shale was first reported to contain 60 scf/ton but
could be as high as 200 scf/ton (Montgomery et al. 2005).
The Barnett is described as a "spent oil-prone source rock with porosity
and permeability developed with thermal transformation of its organic matter
from liquid to gas with resulting maturation-induced microfractures"
(Jarvie et al. 2004). While the Barnett is classified as shale, it is complex
and not homogeneous.
In the core area (Denton and Wise counties), the Barnett is composed of two
producing intervals notated as the upper and lower Barnett. These intervals are
separated by the Forestburg lime, which varies in thickness from 20 ft to more
than 150 ft.
When production from the lower and upper Barnett is commingled, the lower
Barnett contribution is 75–80% of the total. This value has been verified from
production logs and from measuring production when isolating the intervals and
producing them individually.
The lower boundary (Viola/Simpson) pinches out west of the core area. The
Ellenberger is a known water source, so stimulation of the lower Barnett
without the Viola/Simpson can lead to high water production. Another potential
for water production is the Viola, which in some areas has high
Historical Completion Practices
The first stimulation completion of the Barnett used nitrogen gas as the
injection fluid. In early Barnett development, a concern about the high clay
content in the shale led to precautions when using water-based fluids. An
average mineral analysis from samples collected in Wise County, Texas, is given
in Table 1.
Early completion fluids tended to be foamed or gas-assisted. Our data set
begins approximately 4 years before the first SWF was attempted. Reasons for
this transition were predominately driven by economics. SWFs provided the
operator with a substantial savings in stimulation costs; however, the ability
to place high concentrations of proppant was eliminated. SWF began in 1997–98,
and the assumption was that the Barnett would respond to a sand concentration
of less than a monolayer and yield commercial production (Grieser et al.
The lower Barnett was the only interval completed during the early
development of the Barnett field using XLG-type treatments. The upper Barnett
interval was added to the completion when the SWF era began. The addition of
upper and lower net pay in the wells treated with SWF is the reason for the
extra thickness. The cost savings that were realized with the evolution to the
SWF enabled the additional expenditure for completing the upper Barnett.
Stimulation treatment averages and production outcome are given in Table 2 for
XLG fracs and SWF.
© 2008. Society of Petroleum Engineers
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- Original manuscript received:
28 February 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
19 September 2007
- Manuscript approved:
16 December 2007
- Version of record:
20 September 2008