Data Analysis of Barnett Shale Completions
- William V. Grieser (Halliburton Energy Services Group) | Robert F. Shelley (RTA Systems Inc.) | Bill J. Johnson (Halliburton Energy Services Group) | Eugene O. Fielder (Devon Energy Production Co. LP) | James R. Heinze (Devon Energy Production Co. LP) | James R. Werline (Devon Energy Production Co. LP)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- September 2008
- Document Type
- Journal Paper
- 366 - 374
- 2008. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 2.7.1 Completion Fluids, 6.1.5 Human Resources, Competence and Training, 3.3.1 Production Logging, 7.6.4 Data Mining, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 1.2.3 Rock properties, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.5 Gravel pack design & evaluation, 5.8.2 Shale Gas, 1.6.9 Coring, Fishing, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.2.2 Perforating
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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 water-production potential.
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. 2003).
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.
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