新升级PnP完井工艺有效节省作业成本（下）

SETTING PLUGS

A setting tool can be used for thousands of runs in its life span; however, it is important to document each run and get certified every 1,000 runs or less. Proper power charge selection is an important factor in successful plug setting. Plugs like the Boss Hog model are set in a two-step process. We recommend using standard charges with 10-to-40-sec setting times, because fast-acting charges may set plugs too quickly for them to set properly. Slow charges include additives to slow their activation, and tend to be brittle and prone to cracks and voids. Slow set charges also contain a small pill, like a secondary charge, that can fall out of place and keep the charge from burning. Both problems can prevent the setting tool from releasing its full power and make the tool more likely to not shear properly in horizontal wells.

When setting plugs with the ball-in-place feature, operators should pump at 2 to 3 bbl/min., to keep the ball in its seat during the setting process. Once the plug is set, a 100-to-200-lbf line weight loss and a 200-psi pressure increase will be noted at surface.

PLUG DRILL-OUT

After all stages have been stimulated, the composite plugs have to be drilled out to establish a clear casing ID for production. Shorter, lighter-weight plugs can be drilled out in about half the time required for previous composite plugs.

Before drill-out operations, we recommend using Cerberus software (or a similar package) to model the expected performance of the coiled tubing string and BHA proposed for use on the drill-out. The software helps specify chemical programs for debris removal and determines whether the string and available circulation can remove all plugs, including those near the toe, without getting stuck.

In most wells with 5.5-in. casing, a 2?- or 2?-in. CT string is recommended, instead of the more common 2-in. coil size. The larger coil enables high flowrates and use of 3?-to-3?-in. OD even wall downhole motors with slow-speed, high-torque power sections. These mud motors can drill out plugs without stalling, and can handle high enough flowrates to create AVs of 240 ft/min. or higher, to effectively circulate cuttings back to the surface.

The drilling bit/mill should be gauged at 99% to 100% of the casing ID drift, as it provides full coverage of the plug and prevents production of larger debris, as well as coring of the plug. A sealed bearing roller cone bit is recommended, as it produces consistently smaller cuttings. This is due to its rotary crushing action of three points, versus a shearing action enacted by one solid cutting interface of a mill. With more innovative designs of sealed bearing roller cone bits, the longevity of the bit has greatly improved—especially in 5.5-in. or larger casings. In a 4.5-in. casing, a sealed bearing roller cone bit may still be used in conjunction with a low-speed, high-torque motor, as well as drilling best practices of minimum weight-on-bit (WOB). This reduces the risk of overheating bearings and potentially losing a cone. New mills—specifically designed for plug drill-out operations—have performed better than previous five-blade mill designs. This is due to their less aggressive facing and smaller water courses.

Until recently, standard practice during plug drill-out operation was to perform short trips—pulling the CT string out of the horizontal section, while circulating gel sweeps to effectively clean the hole and prevent sticking. In addition to taking several hours for each trip, this practice reduces the working life of the CT string and increases the overall water and chemical volume for the operation. To eliminate short trips, WOB is kept to a minimum during drill-out to achieve small particle cuttings. Light to moderate viscosity gel sweeps are timed carefully, so that they exit the bit as the plug finishes drilling. This helps entrain all the cuttings and facilitate an effective cleanout.

Flowback is also a key component to drill-out success. Ensuring that the flowback rates are matching—if not slightly exceeding the pumping rate (underbalanced), without drawing in from formation throughout the overall operationis critical to maintain turbulent flow throughout the wellbore. Turbulence allows continuous entrainment of the solids into the main flow regime, to effectively transport the cuttings back to surface. This operation requires close cooperation between the CT operator, pump/chemical supplier and flowback operator. The extra effort can result in significant improvements in efficiency and lower overall cost, as well as achieve earlier production from the well. For example, our company has recently worked with numerous operators in the Rockies to safely reduce drill-out times from 36-60 hr to 10-12 hr.

CONCLUSION

The PnP operation is the completion method of choice in many unconventional basins throughout North America. By optimizing job planning, wellsite coordination, plug selection, running and setting procedures, and drill-out and debris removal processes, operators can realize significant savings in time and cost, while improving productivity from their wells.