The economic viability of field-development projects in low-permeability or “tight” gas sands depends on identifying optimum field well spacing in order to maximize gas recovery with the fewest number of wells.

The type and effectiveness of the stimulation treatment is key to optimizing well spacing.
Figure 1. Location of Bossier tight gas sand fields in Freestone, Leon and Robertson counties, Texas. (All figures courtesy of Anadarko)  
Most wells completed in tight gas sands require some type of hydraulic fracturing to achieve economic production. Wells with longer, more conductive fractures recover more gas over a larger drainage area, thus requiring fewer wells drilled on a larger spacing.

Depending on the type and size of stimulation treatment, hydraulic fracturing may be very expensive, often representing a significant portion of total well-completion costs. However, simply reducing stimulation costs with little or no improvement in stimulation effectiveness is not necessarily sufficient to optimize development, particularly if more wells must be drilled to maximize gas recovery. Therefore, it is crucial that the proper balance be found between well spacing, stimulation-treatment effectiveness and gas-recovery efficiency.

Overview of water-frac technologies

Water fracturing or “water fracs” were revived in the 1990s as less expensive alternatives to the large conventional gel treatments commonly employed during the 1980s. Although excellent for transporting proppant, these gels often damaged the fracture, usually generated high-net fracturing pressures and were expensive.

Water fracs generate fractures by injecting water with little or no proppant. “Slick-water fracs” employ linear gels or friction reducers to the water. Water fracs can generate similar or sometimes better production responses than large, conventional gel treatments. Microseismic imaging has shown that water fracs can create very long fractures. However, since water is less efficient than gels at carrying proppant, the effective fracture half-lengths may vary significantly, depending on proppant concentration and placement effectiveness.

The use of little or no proppant in a water frac may also result in low fracture conductivities. Laboratory studies have shown fracture conductivity may be either proppant- or asperity-dominated, depending on both proppant and rock mechanical properties. Under asperity-dominated conditions, fracture conductivity depends on the surface roughness or asperities created on the fracture face. High conductivity water fracs can be generated in the absence of proppant only when rock displacement creates ample surface roughness to provide sufficient fracture width. Similar observations were made with low-strength and low-concentration proppants. As a result, effective fracture conductivities are often difficult to predict when little or no proppant is used.

Hybrid water-frac technologies, which combine the advantages of both conventional gel and water-frac treatments, were developed in the early 2000s to improve stimulation effectiveness while maintaining low costs. Hybrid water fracs still use water to generate fracture width and length while keeping net pressures low. Following creation of fracture geometry, gels with relatively low guar concentrations are used to transport proppant down the fracture. Lower settling rates associated with the gels also allow a more uniform and consistent distribution of proppant placement prior to fracture closure.

Bossier sand stimulation practices
The first Bossier sand stimulation treatments were performed from 1995 to 1997 by Anadarko in fields located in Freestone, Leon and Robertson Counties of Texas (Figure 1). Early stimulation treatments consisted of high polymer-loading, cross-linked fluids carrying large proppant volumes. Typical guar concentrations ranged from 40-50 lb polymer (HPG) per 1,000 gal fluid. Fracture fluids were cross-linked with
zirconate and usually contained several hundred thousand pounds of 20/40 proppant. The objective of these early treatments was to create optimal conductivity by packing the fracture and creating tip screen-outs.

Unfortunately, the well performance was frequently disappointing and was attributed to short effective fracture half-lengths, probably a result of both uncontrolled fracture height growth and gel damage in the fracture. These treatments were also very expensive.

To reduce costs and improve well performance, the operators initiated a field-wide water-frac
  Figure 2. Computed and average effective fracture half-lengths for 18 wells evaluated in field study.
program (1998 to 2000). Initial treatments included 5,000 to 10,000 bbl of “slick water” but typically no proppant. These slick-water fracs were significantly less expensive than the cross-linked treatments, and initial gas production rates were often as high as wells stimulated with conventional gel treatments. Well performance analyses indicated effective half-lengths of 30 to 60 ft (9.15 to 18.3 m) and effective conductivities on the order of 10 mD per ft.

The next phase (1999 to 2001) of stimulation treatments continued to be slick-water fracs but included some 20/40 sand at low concentrations. Because of limited fracture widths generated with the slick-water treatments, only 20,000 to 40,000 lb of 20/40 proppant could be placed effectively in the formation. Although higher initial production rates were observed with proppant than without, the operator continued to seek improvements, especially in effective fracture lengths.

During the time period 2000 to 2001, water-frac treatments used even higher proppant concentrations (greater than 100,000 lb), but also began experimenting with smaller proppant sizes. In particular, 40/70 proppants were found to be very effective. Use of smaller proppant sizes allowed a much larger quantity (often exceeding 200,000 lb) of proppant to be placed with the slick water. Not only did initial production rates increase significantly, but the production behavior suggested longer effective fracture half-lengths were generated. Well performance analyses indicated effective fracture half-lengths ranged from 100 ft (30.5 m) to as much as 230 ft (70.15 m). However, a significant increase in effective fracture conductivity was not observed.

The objective of the last phase (2003 to present) of Bossier sand stimulation treatments was to further increase both effective fracture conductivity and length using a hybrid stimulation technique. Initial Bossier hybrid water-frac treatments included pumping slick water initially to create fracture geometry and followed by relatively low (30-35 lb per 1,000 gal) borate cross-linked gel carrying 20/40, 40/70 or a mixture of proppant sizes for increased fracture length and conductivity.

Results and conclusions
In 2003, the operator initiated a comprehensive evaluation program designed to assess and compare the stimulation effectiveness of conventional water-fracs against hybrid water-fracs. Table 1 summarizes the stimulation treatments for the 18 study wells evaluated in the program. Treatments ranged from small water fracs with little or no sand, water fracs with large sand concentrations, and hybrid water fracs.

Stimulation effectiveness — measured in terms of effective fracture half-length and
Figure 3. Computed and average effective fracture conductivities for 18 wells evaluated in field study.  
conductivity — was evaluated using short-term pressure buildup test data, combined with long-term production data analysis using a material balance decline type curve methodology. Estimates of reservoir permeability from the production data analysis were used as input to estimate effective hydraulic fracture properties from the pressure buildup tests. Integrating results from both types of data analyses provided more unique and accurate assessments of the created fracture properties.

Table 2 summarizes all of the results from the evaluation program, while Figures 2 and 3 show the measured effective fracture half-lengths and conductivities, respectively, for the 18 study wells. Study results suggest the following:
•    On average, a hybrid water-frac technique generated longer effective fracture half-lengths and greater effective fracture conductivities than both small and large conventional water-fracs;
•    Although the average effective fracture conductivity in the hybrid water fracs was larger than conventional water fracs, the inability to obtain greater conductivity consistently suggests more field trials are required to optimize the hybrid water fracs;
•    For reservoir rocks with mechanical properties similar to the Bossier sands, proppant is required to
generate long effective fracture half-lengths. However, there does not appear to be a discernible correlation between effective fracture conductivity and quantity of proppant used;
•    The use of higher proppant concentrations with conventional water-fracs does not appear to generate longer and more conductive fractures consistently. This lack of improvement may be attributed to ineffective and inconsistent placement of proppant prior to fracture closure; and
•    The low costs combined with more effective stimulation results will help the operator optimize field development in the Bossier tight gas sand play.