BJ Services pump trucks and equipment converge on a pair of Barnett Shale wells for a simultaneous fracture stimulation treatment. (Graphics courtesy of BJ Services Co.)

Large-volume slickwater fracture stimulation has proven very successful in naturally fractured shale reservoirs such as the Barnett Shale of North Texas, the Fayetteville Shale in Arkansas, the Marcellus Shale in Appalachia Basin, and many other shale reservoirs. These shales require hydraulic fracture stimulation in order to obtain commercial production. The characteristics and mineralogical properties of the shale allow for the creation of complex fracture geometries that contact large surface areas during fracture stimulation, which all contribute to production.

The evolution of the development and transition from vertical wells to horizontal wells has been key to enhancing the potential reserve recovery in many areas. This has been particularly important in the urban environments where drill sites are limited. Typically, wells in these shales are long horizontal laterals ranging from as little as 1,800 to more than 4,000 ft (549 to more than 1,220 m). These wells are typically fracture stimulated with large, multi-stage treatments that reach deep into the formation and potentially interconnecting the natural fracture network to contact as much reservoir rock as possible.

A recent completion trend in the North Texas Barnett, Arkansas Fayetteville shales, as well as others, such as the Woodford Shale in Oklahoma, is the technique of simultaneously fracturing two or more parallel wellbores. These enormous “simo-frac” operations are designed to take advantage of communication between wells to enhance the degree and intensity of fracturing in the area between the well bores, maximizing communication with the natural fractures.

The concept sounds good in theory, but the ultimate proof is in the economic return.

Slickwater designs

A typical Barnett shale slickwater frac involves pumping 500,000 to 1,000,000 gal of fluid and 250,000 to 700,000 lb of proppant at 50 to 80 bbl/min in each of five to seven stages. The actual treatment design from the standpoint of exact fluid and proppant volumes can vary based on the well's location — whether in the “core” or “non-core” area or certainly depending upon proximity to water bearing intervals (Ellenberger) below the Barnett. In many cases, treatments start with 100 mesh or 40/70 mesh proppant because the small particle diameter allows the low-viscosity water to carry it deep into the formation. Most treatments typically tail-in with a smaller volume of 20/40 mesh proppant to maximize near-wellbore conductivity. Pump rates at the lower end of the range are aimed at helping contain fracture height growth in “non-core” areas that do not have a natural barrier to prevent accidentally breaching the porous, wet Ellenberger formation.

Hydraulic fractures created during treatments in these shales cannot be considered the same as conventional fractures in that typical two-wing fracture geometry does not occur. The fracture characterization is much more complex, as has been evidenced through utilization of microseismic technology to “fracture map” the stimulation treatments. The result of microseismic mapping has shown that fracture stimulation in the Barnett can create a fracture “fairway” with broad extent and length with multiple fracture orientations.

Experience has shown that these large stimulation treatments can communicate through the fracture system to offset wells as far as 1,800 ft (549 m) away, resulting in improved production on the stimulated well — but it may also cause reduced production at a producing offset or even kill the offset. This is important because in many cases, parallel well bores are being drilled in the Barnett, with spacing between the laterals ranging from 500 to 1,000 ft (152 to 305 m) apart, depending upon lease arrangement.

The simo-frac technique takes advantage of the predicted communication to enhance the degree and uniformity of inter-well fracturing, thereby expanding the fracture network area. Although it may not be evident during the stimulation of the parallel well bores, the potential effect of stress and stress shadowing suggests potential increases in the additional reservoir rock contacted not only away from the well bore but also between the well bores. Another advantage to this process particularly within the urban environment and in areas with multiple wells on a single pad is that this process allows wells to be completed more quickly, thus helping improve well economics.

For example, an early 2006 simo-frac operation stimulated two neighboring wells in Fort Worth, Texas. The wells were drilled from one pad, about 30 ft (10 m) apart, with roughly parallel horizontal trajectories ending about 1,000 ft (305 m) apart. The proximity of the wells suggested that sequential stimulation might result in fluid communication from the second well effectively killing the first well. In addition the two wells could be completed faster and more efficiently. Furthermore, a simultaneous fracturing operation would maximize the fracture network created between the wells and bring both wells on sales faster than sequential operations.

The job pumped as designed with a total of approximately 3.5 million lb of proppant and 250,000 bbl of slickwater fluid in nine stages on the wells (four stages on one well and five on the other).

After treatment, both wells produced at significantly higher rates than any offsets; one produced an average of almost 9 MMcf/d of gas for more than 30 days, compared with offsets in the 2 MMcf/d to 5 MMcf/d range. A production comparison can be seen in Figure 2.

In another example, during late summer/early fall 2007, BJ performed simultaneous fracture stimulations on three roughly parallel horizontal well bores north of Fort Worth. The enormous simultaneous fracturing operations involved 29 pump trucks with a total of more than 55,000 hydraulic horsepower pumping 351,000 bbl of fluid and nearly 5.5 million lb of sand. The resultant production from all three wells is among the highest in the area.

In December, the company pumped simultaneous fracturing operations on three wells in the Fayetteville shale of Arkansas. Three of the company’s districts provided high-rate (+100 bbl/min) frac fleets to pump more than 6.6 million pounds of sand over some 22 hours. Three treatment vans — one for each frac fleet — stayed in constant communication so engineers could fine-tune each stage on each well during the course of pumping.

The service company has performed simultaneous fracture stimulations to complete 12 additional sets of wells, including three triple fracs using simultaneous operations. Planning is underway for more operations, including a potential for quad frac in the not too distant future.

Logistics are critical

Careful planning and logistics are critical. First, some locations require creative arrangements in order to squeeze the necessary equipment into the allocated space so it can function as required. Second, the fluid and sand volumes must be arranged well in advance. The service company and operator must work closely together though all phases of the planning, drilling, and completion process to ensure an optimum treatment. It is particularly important to develop a plan for the proper amount of treatment fluid will be available because these simultaneous treatments require massive volumes of water. In addition the location must be configured to allow for continuous supply of chemicals, fuel and proppant for the treatments. For example, before starting the Arkansas operation, 76 sand trucks were lined up at location, waiting to be off-loaded “on the fly” over the 22-hour pump time.

As with any fracture stimulation, candidate evaluation is important to achieving a successful result. Consideration must be given to such variables as the reservoir characteristics, well spacing, well configuration and well azimuth, as well as several other factors to maximize the potential for success.