Technology aids fracturing success

As shale euphoria swept through the North American E&P industry during the late 2000s, the primary advancement in shale development strategy involved scale. Production was enhanced with longer laterals and increased segmentation.

As a consequence, demand surged for standard shale development equipment. Given this emphasis, equipment providers have been the primary beneficiaries of the shale revolution to date. However, as equipment utilization and pricing normalizes, value creation could transfer toward technology.

Faster fracing

Plug and perf (PNP) is the traditional method of executing a multistage stimulation program. This method involves cementing in production casing in the lateral section of the well. The section to be fractured is isolated by setting bridge plugs via wireline or coiled tubing (CT).

Stimulation dominates spending in plays such as the Eagle Ford. (Images courtesy of Bernstein Research)

Next, the casing is perforated, and the frac fluid is pumped into the well. This process is repeated until each stage is fractured. Finally, CT is used to drill out the plugs and open the well bore for production.

While PNP is reliable and the components are typically readily available, it requires multiple trips into the well, driving costs toward 40% to 50% of a shale well's total cost.

As a result, service companies have introduced various completion technologies to expedite the process. Open-hole completion systems have been around for a decade but have gained increased traction recently. These systems use hydraulically set mechanical packers on the outside of the production casing to isolate sections of the well bore. Instead of using a perforating gun to provide access to the reservoir, sliding sleeves cover frac ports and are opened by dropping an actuation ball into the well, which lands in a cradle and isolates each stage. Progressively larger balls are dropped to complete stages from the far toe to the near heel of the lateral section. After pumping is complete, the balls are simply pumped out to reopen the well bore.

The major advantage to this method is speed, as the entire fracturing treatment can occur in a single pumping operation, reducing the time required to execute each stage by approximately 75%. Initial drawbacks were the limited number of stages built into the systems' design as well as reliability. However, many companies have introduced enhanced systems to address these issues.

Baker Hughes' FracPoint EX-C appears to have the edge in stage capability as this system can execute up to 40 stages by using balls that vary in size by just 1/ 16 in. Competing systems include DeltaStim from Halliburton (max 26 stages), StackFRAC HD from Packers Plus (max 20 stages), and Falcon from Schlumberger (max 20 stages).

Packers Plus has pushed the sliding-sleeve system further with a repeater port technology built into its QuickFrac system. Rather than activating a single stage, each ball dropped opens two to five stages. Each interval has a limited entry setting to allow only a portion of the fracturing fluid to enter. Thus, the number of pumping stages is only a fraction of the number of stages actually fractured, reducing time and costs; this is offset by a reduction in frac propagation due to less energy used per stage. However, the product can execute up to 60 stages in a single well.

Conventional slickwater bed load proppant transport

In Canada, where low-flow pumping jobs into shallow wells are common, companies have developed fracturing through CT, also known as annular fracturing. In this approach, production casing is cemented in place before a sand-jetting tool on CT is run downhole to perforate the casing. Next, frac fluid is pumped down the casing/CT annulus.

The benefits of this approach are virtually limitless stage creation, no restrictions on placement, speed, and less horsepower (up to 50%) required due to pumping a single perforated section instead of a cluster.

However, pumping down the CT restricts flow to 20 to 30 bbl/min, which is at the low end of the useful spectrum.

Sliding sleeves also can be used in combination with CT. Rather than ball activation, the sleeves are opened via CT followed by an annular frac. This approach further reduces the time required to execute a stage since sand jetting is avoided, although the ability to change the placement of the fractures on the fly is eliminated.

Trican’s FlowRider solution causes microscopic air bubbles to adhere to sand, making it as transportable as ultra-lightweight proppant. Slickwater with proppant transportation modifier

Another approach eliminates packers for zonal isolation by using burst point collars with coiled-tubing stimulation. Burst point collars such as Trican's Burst Port System are casing collars containing pre-milled ports sealed by burst discs. The joints are then straddled by the Trican Selective Stimulation Straddle Tool (C2C), which creates a pressure zone around the collar, causing the ports to burst at their designated pressure point. The C2C creates the pressure zone by using movable cups with frac fluid pumped down CT and into the zone of focus. After stimulation, the C2C unseals the zone and moves onto the next.

This approach is fast, with each stage taking less than an hour, and eliminates the use of actuation balls, thereby leaving the well bore completely open post-job. However, flow rates are again at the low end of the spectrum.

The disappearing ball act

Baker Hughes has turned to nanotechnology and developed In-Tallic dissolving frac balls. The balls consist of microscopic particles of magnesium, aluminum, and other alloys that are bound together but dissolve in brine. The result is a light but strong material that can be shaped into perfectly round balls, provide a seal downhole, and then completely dissolve in a few weeks. The company also is developing a holster made of the same material to eliminate the need for drill out post-stimulation. Schlumberger offers a competing system that uses a dissolvable dart to activate sliding sleeves within its nZone system.

Proppants lighten up

New proppant technology includes ultra-lightweight polymer proppants with specific gravities approaching water. The settling rate of the ultra-lightweight proppants is much slower than sand and ceramics, reducing the volume required and partially offsetting the higher per-unit cost.

An interesting alternative is Trican's FlowRider, a solution that causes microscopic air bubbles to adhere to sand, making it as transportable as ultra-lightweight prop-pants. This reduces the volume required for a conventional job while enhancing well productivity due to improved connectivity.

A different proppant strategy is channel fracturing, which was recently enhanced by Schlumberger and sold under the HiWay brand. Fibers are used to coagulate the proppants, and the clumps establish a pillar structure with channels to facilitate flow and prevent dispersion during pumping.

As margins for wellsite capital equipment normalize, the primary driver of value creation within the onshore North American oil services industry could transfer toward technology promoting improved efficiency and performance in addition to product integration. In fact, technology has the potential to hasten the process of margin normalization by improving the effectiveness of the machinery.