Completion Codes

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, such as high-efficiency rigs, frac pumps, frac manifolds and fluid tanks.

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. Here are some of the ways technology is evolving to drive down completion costs while boosting production.

Faster fracing

Plug-and-perforate is the traditional method of executing a multistage stimulation program. This method involves cementing in production casing in the lateral section of the well. Isolation of the section to be fractured is accomplished by setting bridge plugs via wireline or coiled tubing.

Next, a perforating gun is sent downhole to perforate the casing, and after removal, the frac fluid is pumped into the well. This process is repeated until each stage is fractured. Finally, coiled tubing is used to drill out the plugs and open the wellbore for production.

While this process is reliable, and the components are typically readily available, multiple trips into the well to set plugs, perforate, stimulate and then drill out the plugs are time consuming. Compounded by expanding stage counts and, more recently, cyclical cost inflation, this process has driven stimulation 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. Many of these new methods were first used in the Canadian and Bakken shale markets due to the plays’ shorter active pumping seasons, but now are offered across a greater number of basins.

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 wellbore. 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 wellbore.

Sliding sleeves offer a step change in efficiency.

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 some 75%. Initial drawbacks were the limited number of stages built into the systems’ design, as well as reliability. However, 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 of an inch. Competing systems include DeltaStim from Halliburton (max 26 stages), StackFRAC HD from Packers Plus (max 20 stages), and Falcon from Schlumberger (max 20 stages). Schlumberger also offers the nZone Ball Drop Valve, which leverages the ball activation method, but through individual valves installed with the production casing rather than a stand-alone system, making it advantageous in extended-reach applications.

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.

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

CobraMax® DM service allows placement of a number of fracturing stages in a horizontal section with the flexibility of downhole changes in proppant concentration. At top, jetting perforations; middle, concentrated sand slurry flowing down coiled tubing mixed with clean frac fluid; and bottom, the sand plug set as diverter in preparation for the next frac interval.

At the end of each stage, either a re-settable bridge plug or a sand plug is set to isolate the next section. If sand plugs are employed, after all stages are complete coiled tubing is used to wash out the plugs. 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.

A drawback is that pumping down the coiled tubing restricts flow to 20 to 30 barrels per minute, which is at the low end of the useful spectrum and relegates the systems to select basins such as the Permian, Barnett, Canadian Bakken and Cardium. Baker Hughes’ OptiFrac SJ and Halliburton’s CobraMax (sand plug) and CobraFrac (resettable plug) systems are examples of this technique.

Sliding sleeves can also be used in combination with coiled tubing. Rather than ball activation, the sleeves are opened via coiled tubing 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. Products in this category include Baker Hughes’ OptiPort, and NCS Energy’s Multistage Unlimited system, which claims five to 10 minutes per “stage” (the equivalent of a half hour to full hour per standard stage in a conventional job).

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 Trican’s 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 coiled tubing 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 wellbore completely open post job. However, flow rates are again at the low end of the spectrum.

The disappearing ball act

Soon after commercialization of ball-activated fracturing sleeves, operators began noticing production variations on a small subset of wells. Some theorized that one issue could be failure of traditional balls, resulting from damage during the trip downhole. In addition, the balls must be pumped out and the holsters are often drilled out to open the wellbore, with the latter requiring coiled-tubing services.

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, which 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. Baker is also 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

One of the primary problems with conventional proppants—namely, sand, resin-coated sand, and ceramics—is rapid settling of the proppant at the bottom of the induced fracture near the wellbore, reducing the length of the fracture once pumps are turned off. The solution has been to pump a much greater volume of proppant to ensure that a sufficient amount penetrates deep into the fracture network.

The alternative is to use 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.

These proppants are also nearly perfectly spherical, which improves compressive strength and will deform rather than crush, limiting the amount of produced fines. Ultra-lightweight proppants can also be used with foams, which inflict less damage to shale reservoirs than slickwater fracs. Many pumpers offer ultra-lightweight proppants, including Halliburton (Monoproppant), Baker Hughes (LiteProp), Trican and Canyon.

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 proppants. 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 utilized to coagulate the proppants, and the clumps establish a pillar structure with channels to facilitate flow and prevent dispersion during pumping. The cost of the fibers, gel fluid and slight tweak to the pumping equipment is offset by reduced prop-pant volumes, superior fluid recovery, and enhanced production. A drawback is that HiWay cannot be used in extremely hot reservoirs such as the Haynesville.

After utilizing HiWay on a series of test wells, Petrohawk reported a 37% increase in production within natural gas wells and a 32% increase in high condensate yield wells in the Eagle Ford. Encana forecast a 17% increase in performance using the technology in the Pinedale area of Wyoming.

Operators also report a 25% to 40% drop in proppant usage and a 30% to 40% reduction in water usage, according to Schlumberger. Since commercialization in June 2010, Schlumberger has conducted more than 550 jobs across the U.S. for 20 different operators. HiWay has also been deployed in Mexico, Argentina, Russia and Canada.

Frac mapping and modeling

Trican’s FlowRider solution causes microscopic air bubbles to adhere to sand, making it as transportable as ultra-lightweight proppants.

Another recent development is the growth in monitoring to determine stimulation treatment effectiveness. Mapping the fracture propagation in one well can aid in the design of the next, to maximize reservoir contact and avoid water-bearing zones and faults. The mapping can be executed by either an array of geophones (pinpointing the sound of cracking rock) or tilt-meters (measuring changes in horizontal orientation) on the surface, or alternatively, downhole via monitoring wells. Surface monitoring is less expensive, but downhole can offer superior data quality if close to the well.

The data is attractive to operators since it is captured and processed in real time; however, all of the methods suffer from the same limitation—namely, they measure the fractures and not the placement of the proppants. The prop-pants maintain connectivity throughout the well after the stimulation treatment.

All of the integrated service companies offer frac mapping. Pinnacle, a Halliburton subsidiary, pioneered offset wellbore microseismic mapping. Schlumberger offers StimMap through WesternGeco, Baker Hughes offers VSFusion through a joint venture with CGG-Veritas, and Weatherford also offers a suite of microseismic services. There are also many smaller competitors, including ION Geophysical (IO), OYO-Geospace (OYOG) and Micro-seismic (private). However, Halliburton and Schlumberger appear to have a competitive edge in incorporating the collected data into a more comprehensive reservoir model.

Pinnacle leverages Landmark’s reservoir-modeling expertise, and Schlumberger’s StimMap service leverages Petrel’s modeling expertise to offer seismic-to-simulation capabilities. Baker Hughes and Carbo Ceramics (CRR) both offer modeling software, but appear to be a step behind.

The goal for all is to move beyond geometric (or evenly spaced) fracturing to pre-designed programs targeting the most productive zones. With a sizable (10% to 40%) number of stages yielding disappointing production rates, it may behoove operators to more intelligently design the completion program, as long as the cost of doing so is attractive.

Investment conclusion

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.

The large-cap service companies are clearly advantaged during the next stage of shale development in North America. This likely underlies their enthusiasm, at least in part, to continue adding capacity even as pumping margins compress and gas prices linger below $3 per thousand cubic feet.

Scott Gruber, CFA, has been Sanford C. Bernstein’s senior research analyst for U.S. oil services since 2009. He was voted the Best Up & Comer Analyst within his sector in Institutional Investor’s All-American Research poll in 2010. He holds a degree in economics from Princeton University.