TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Barnett shale is an unconventional gas reservoir that is currently estimated to extend over 54,000 square miles. In an effort to improve well economics and to reduce the number of surface locations in populated areas, there has been a rapid increase in the number of horizontal wells being drilled and completed. 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 seen when completing horizontal Barnett shale wells. These difficulties are manifested 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 have represented 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 versus 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 upwards of an additional 25% per stage. Using these optimized strategies has reduced the number of stages where fracture initiation difficulties have been encountered by 74%.

Horizontal wells represent a growing percentage of the drilling activity in low permeability reservoirs within the United States. With effective stimulation techniques, these wells have demonstrated favorable economics compared to vertical wells in the same reservoir due to the much larger hydraulic fracture surface area that is created. In order to achieve optimum horizontal well stimulation, the lateral section must be characterized and the perforation placement customized to account for reservoir changes along the wellbore. In most cases evaluation is limited to a gamma ray measurement while-drilling (MWD) tool and, periodically, mud log. While these tools can identify significant structural changes and hydrocarbon shows along the lateral, they provide little stratigraphic information, no natural fracture information, and no stress information. One log evaluation tool that is being used more frequently in horizontal wells is the formation imager. It produces electrical images of the borehole that provide detailed structural information such as faulting and natural fracturing. The images can also be used to estimate the stress state along the lateral via the presence and orientation, or absence, of drilling induced fractures. With this information important completion decisions can be made such as: lateral isolation need, stimulation staging requirements, perforation cluster design and spacing. Images can also identify offset well hydraulic fractures when they are intersected. This too can drive perforating and completion strategies, as well as future infill well placement. This paper describes how formation images have been used to implement changes to the completion process in horizontal Barnett shale wells. Stimulation staging and perforation placement strategies now utilize this information. In addition, actual stimulation pressure responses and microseismic activity are compared to those predicted from image logs. Infill drilling strategies, taking into account the location of offset hydraulic fractures, are reviewed as well. Barnett Shale History Development of the Barnett Shale in the Ft. Worth basin began in 1981 with the drilling of the Mitchell Energy C. W. Slay #1. For the first few years small CO2 or N2 foam treatments were performed as the well count slowly increased into the 20s. From the mid 1980s to the first half of the 1990s, massive hydraulic fracture treatments averaging 600,000 gallons of crosslinked gelled fluid and 1,400,000 pounds of sand were the norm. While improving the EUR to approximately 1 Bcf in Denton and Wise Counties, economics were marginal due to high completion costs and low commodity prices. By 1996 the well count exceeded 300. In 1997 Mitchell Energy began to experiment with Slickwater stimulation treatments. These treatments contained roughly twice the fluid volume of the large crosslinked treatments previously pumped, but less than 10% of the proppant volume. Well performance was somewhat better than the crosslinked jobs, but stimulation costs were reduced by approximately 65%. These treatments have become the norm in the Barnett because of the extremely large fracture surface area that can be economically generated. The stimulation cost reductions allowed Mitchell to complete the Upper Barnett that is present in Denton and Wise Counties in addition to the Lower Barnett. This increased EURs by roughly 20% to 25%. Also in the late 1990s Mitchell began to experiment with restimulation treatments. In many cases well performance matched or exceeded the original initial production rates. Refracturing of wells originally completed with gelled fluids has been most successful. It is believed that this is due to the new and much larger formation surface area that is exposed to a pressure drop. It is apparent from microseismic monitoring that these treatments are activating natural fractures normal to the maximum horizontal stress (sH) that are frequently present. This happens to a smaller degree with viscous fluids1. A consequence is that refracturing of wells originally completed with Slickwater is generally less successful since the refracture geometry is less likely to change as compared to gel fractured wells.

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.