Efficient fracturing techniques used with an appropriate multistage fracturing completion can achieve higher initial gas rates, increased recovery rates, and reduced completion costs.

Remote, auto-sequenced ball drop improves operational safety.

One-trip multistage fracturing completion technology reduces rig time and cost for hydraulic fracturing, accelerates production, and improves reservoir drainage. When coupled with effective fracturing strategies and best-practice procedures, the system provides improved production from unconventional gas formations.

The Frac-Point system is an example. This is a single-trip multistage isolation completion fracturing system that provides the ability to selectively pinpoint fluid displacement and volume during openhole fracture operations. This cost-effective technique provides openhole isolation between zones, zone lobes, fault lines, poor permeability sections, or questionable water saturation sections.

Unconventional formations

The so-called unconventional natural gases are tight gas, coalbed methane (CBM), shale gas, deep earth gas, geo-pressured gas, and methane hydrates (Zahid 2007). Unconventional gas reservoirs require the formation to be fractured by hydraulic means to provide a conductive path and joining the existing fractures and cleats in the reservoir (Zahid 2007).

Due to the characteristic differences between CBM reservoirs and conventional oil and gas reservoirs, largely accepted norms in the industry literature are often inadequate to address problems associated with hydraulic fracture stimulations (Valencia 2005). Typical problems associated with these types of reservoirs are low permeability and reservoir compartmentalization for tight gas, shale gas and coalbeds and the finding of suitable permeable coals that contain a large volume of sorbed gas. Because these
types of formations tend to produce at low rates with lower ultimate recoveries (compared to conventional reservoirs), operators place a premium upon invested capital.

Minimizing trips in the well, placement of more effective stimulation treatments, and optimizing rig/frac equipment use are keys to controlling costs and improving recovery.

A single-trip, multistage isolation completion fracturing system that allows selective stimulation of multiple stages, intervals, or zones provides an attractive solution.

Well design

The system can be used in either cased or open hole. The vast majority of installations to date have been open hole. When designing a completion of this type, the number of segments to be isolated, the spacing of each segment, and the isolation of any faults or water-producing zones must be considered. Getting the completion to depth is also a consideration, which may require a torque and drag model. This system has the ability to rotate the liner/completion string in order to get to final depth, and a bit
can be attached to the end of the string if needed.

Completion systems of this type are made up of five primary components: the liner top packer containing a tieback receptacle that is deployed with a hydraulic running tool and set by applied hydraulic pressure; the open hole packers that are used to isolate zones; the frac sleeves and a pressure activated sleeve that provide a communication pathway for both stimulation and production; and a wellbore isolation valve that is used as a closeable displacement control device/sub.

Once the assembly is run in the well, a setting ball is deployed to shift the wellbore isolation valve to positively seal off the tubing and to sequentially set the packers. This type of system requires an openhole element system capable of sealing in variable hole geometries. Once all the packers are set, the wellbore isolation valve acts as a positive barrier to formation pressure. With the frac sleeves closed and the wellbore isolation valve closed, the well is secured. The rig can then be moved and the fracture treatment pumping performed at a later date. Once the fracturing surface equipment is rigged up, applied pressure is used to open the pressure sleeve, and the first stage is ready to be treated. The frac sleeves are actuated by dropping a ball matched to their respective seat sizes. This action creates a barrier to the zone below for selective fracturing and opens the frac sleeve. The sleeves are pinned to shift open with applied differential tubing pressure. Successive increasing ball sizes are dropped to selectively actuate the corresponding sleeves and accurately place fracture fluid in each interval. The ball-actuated frac sleeves can be mechanically shifted back into the closed position. This gives the ability to isolate problematic sections where water influx or other unwanted egress can take place.

Automatic ball drop
An automatic, remote-actuated ball drop/launcher system has been developed. The system provides significant safety enhancement over the conventional technique of manually introducing the balls through either wing or isolation valves plumbed within the pump flowlines. This feature eliminates any guesswork in the sequence of the balls, as the launcher can be preloaded in the shop and transported to the rig site within a lifting frame that can be carried in the back of a pickup truck. The balls are deployed from a secure remote location such as a frac van. The actuation is done either pneumatically or hydraulically, with clear visual feedback when each ball has dropped. The system also has manual backup capability if required.

The convergence and integration of systems and processes developed during the 1990s and in the early years of this decade have provided a foundation for new technologies for unconventional applications such as tight gas. The economic exploitation of tight gas has been challenging because it resides in three locations that are hard to develop: low permeability sandstones and carbonates, gas shale, and coalbeds. New intelligent well technology may hold the key to unlock these vast reserves. Remotely operated hydraulic frac valves now can provide selective control of high-rate stimulation of multiple intervals in horizontal wells, and can improve operation time through the elimination of coil tubing trips. Frac valves may be cemented in place and also can be used after fracturing for simple selective production test and cleanup operations, with the ability to manipulate the valves later to shut off water or gas encroachment (Schrader 2007).

Conclusions

To increase the chances of obtaining high initial gas rates and maximized final recovery of reserves, it is necessary to understand the sedimentation process of the reservoir and direction of maximum permeability in order to select the appropriate drilling orientation and the appropriate direction for transversal fracturing.
The system described here provides a true one-trip completion system that isolates multiple intervals for selective transverse fractures (including high-pressure/ high-temperature applications).

This technique not only improves wellsite efficiency with a methodology that minimizes multiple interventions, but also maximizes the effectiveness of products placed in the reservoir.

Pay zones that were traditionally bypassed due to their assumed marginal economics can be completed economically, leading to increased hydrocarbon recovery from the reservoir and significant improvements in capital and operating expenditures.

The fundamental degrees of mechanical and volumetric success must be properly established. These two aspects collaborate in improving the exploitation of unconventional gas reservoirs. Operators draw proper conclusions and contractors must about the performance of the completion (technology) and the fracture process (technique).

The single-trip multistage isolation completion system offers three key benefits. First, the openhole packers provide the isolation along the length of the liner/completion string. This feature eliminates the need to cement the liner in the lateral section. Second, since the sleeves provide access to the zone of completion for both fracturing and production, no perforating is needed; furthermore, fracture treatments for each section of the lateral can be pumped consecutively on the same day. This eliminates the need for multiple mobilization and demobilization of costly pumping and wireline equipment. Finally, the third benefit is increased production and greater returns.