As an increasing number of unconventional resources and new plays are being discovered and developed, it is apparent that the need for an efficient method to maximize production from these very active plays is more important than ever. Conventional methods such as plugand-perf style completions have been widely accepted, and operators require any new alternative system to provide the same or more coverage as perforating without any added mechanical risk or complexity.

The completion industry has evolved and changed over the last decade with the development of many new technologies, and today operators are drilling more horizontal wellbores than ever before. This advent has created many new market challenges and demands on surface equipment, water resources and, with many operators running multiple projects, engineering supervision.

A primary focus for completion technology development has to be on solving these challenges. Saving even one day of completion time per wellbore has a trickle-down effect that is surprising when sitting down with operators and looking at their projects. Not only does each day saved reduce upfront service costs on location, but it also reduces exposure to safety liability and engineering supervision and most importantly adds a day of initial production.

This was a critical component for an operator in West Texas who presented a horizontal project development to Peak for drilling and completing multiple wells per month. Requiring cement for zonal isolation in the lateral, their requests for an alternative technology to perforating included the additional need for remedial production control and the ability to shut off selected zones post-completion. The operator chose the Peak Completion IsoPort selective fracturing system, which is a fullbore cemented-sleeve system developed over the last decade. The system was implemented, and more than 2,000 stages in total were run. Ranging from as few as 10 stages to as many as 75 stages in a single well, the system allowed this operator to design the completion around each specific wellbore.

The system’s ability to duplicate the perforation design of a conventional system allowed the operator to use proven infield fracturing programs while greatly reducing its water requirements. Saving four days of completion time on average allowed this project to be developed on a much larger scale than originally planned due to the improved economics.

This example of a cemented sliding-sleeve system as one alternative has gained momentum as many operators are searching for innovative, efficient ways to reduce the cost, complexity, and time required of the completion phase. It also has led to many new and exciting tool development programs.

Reduced costs with rigless toe initiation

One such technology eliminates the need for tubing-conveyed perforating (TCP) on horizontal completions with the Trigger Toe Sub toe initiator sleeve. Designed for use in both openhole and cemented applications, this pressure-actuated sliding-sleeve system allows operators to perform a high-pressure casing test before actuating the tool and opening the fluid exit ports for the first stage of the frac.

Elimination of the first-stage TCP run allows cemented sleeve multistage systems to be completely rigless, and they also can be used with traditional pump-down plug operations. A further completion challenge was solved with the ability to quickly and economically initiate toe stimulation on extended laterals where coiled-tubing operational limitations have traditionally restricted operators on the horizontal length of their wells. The elimination of just one TCP run can save many operators a full day of completion time and direct cost savings of up to US $140,000 per well, with the additional benefit of reducing equipment required on location and overall complexity of operations.

With hundreds of runs in many active plays, the substantial cost savings provided by this simple, proven tool make many unconventional projects now economical.

Maximizing efficiency, flexibility

Having the ability to complete essentially an unlimited number of single-stage fracs with the cemented-sleeve systems, operator requirements expanded to match ongoing multicluster perforation configurations with multiple fluid-exit points per stage. Further, for interventionless ball-drop fracturing systems, there was a strong demand as lateral lengths increased to increase the number of stages for complete coverage. Two new technologies were developed: the Expandable Frac System (EFS) and the Super-Port fracturing sleeve.

The EFS replicates perforation clusters through the installation of numerous sleeves per stage and a total of up to 15 stages. One ball is pumped down, actuating all the sleeves per stage. The increased wellbore coverage, along with the ability to adjust the port flow area, allows operators to replicate their previously used perforation fracturing design but with the new benefits.

Operators with projects in the Eagle Ford and West Texas Bone Spring formations have been running EFS with 15 stages and four to six sleeves per stage. Performing the normal cement program with the only changes being the addition of the Peak wiper system, the wells have been fracture-stimulated with a continuous pumping operation average of 30 hours. By using this system, these operators have reduced completion cycle time by eight days. By reducing the number of required fracturing crews and accelerating initial production, these operators have radically improved project economics.

To solve the need for additional stages for extended-reach laterals, the SuperPort was developed, using an advanced seat technology to double the number of available stages for cemented sleeve systems to 32. The precision-engineered tool maintains a standard 10,000-psi differential rating across the ball seat, eliminating the need for customized frac ball materials.

Several deep shale wells have been successfully completed in southeastern New Mexico using the system. With the ability to pump at rates of up to 100 bbl/min, this allows operators to reach higher rates at the toe stages than is normally possible with conventional ball-and-seat systems.

Deciding factors

With full system implementation of one of these technology options, elimination of pump-down operations and the ability for continuous pump time have saved operators up to 12 full days in some areas. The overall reduced cycle time allows more wells to be completed each year. Wells can be completed more effectively with less hydraulic horsepower, water, and associated fracturing fluid products while eliminating the risk of perforating operations and guaranteeing precision fracture placement.

These factors, along with improved safety and reduced liabilities, are just a few of the compelling reasons operators are choosing to run the ball-drop system over traditional pump-down perforating methods to attain efficiency in completions.

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