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Please note, this page is derived from the 2020 ATCE paper: SPE-201412-MS.
When moving tubing into and out of a pressurized well, slips are used to hold onto the pipe. The modern HCU systems have 4 sets of slips: two sets of snubbing slips control pipe during pipe light operations and two sets of heavy slips control pipe during pipe heavy operations. Once the slips bite the pipe, a hydraulic jack is used to move the pipe into or out of the well. The process is relatively fast and consists of one set of slips biting the pipe, the other set opening, the jack moving the pipe about 10 ft, then the other slips grab the pipe again. Snubbing units are able to move pipe into and out of the well without any pressurized fluid escaping. This process is called stripping, which is the act of moving pipe through a closed annular blow out preventer. (Note: when working with wellhead pressures in excess of 3,000 psi, can test the efficient operating limitations of most coiled tubing units.) When working with surface pressure greater than 3,000 psi, all pipe connections must be “staged” into or out of the well in a process called ram to ram staging. An equalizing valve and a bleed-off valve are used to safely move the tubing and couplings through the BOP. The final set of safety devices are the profile nipples installed periodically throughout the tubing string. In the event of a check valve or tubing failure, wireline plugs can be run to isolate the problem.
Rig assist snubbing systems:
The first stick pipe snubbing system began drilling out frac plugs early in the Marcellus shale development. It can trip pipe using the snubbing unit during pipe light and transition periods but quicken its trip time using the workover rig and its blocks during the pipe heavy period. A disadvantage of this package is that it requires the integration of two services to perform one operation. It is vital that both services have exceptional communication during the job.
The HCU eliminates the need for the service rig and consists of a stand-alone unit that mounts on the wellhead after the stimulation treatment is complete. Primary components include the jack assembly, traveling/stationary slips, a redundant series of primary and secondary blowout preventers, a rotary table and makeup tongs, a tubing buckling prevention system, and equalizing loops for the snubbing rams. The HCU typically uses 2 7/8” tubing with PTECH or PH-6 premium connections to carry a downhole motor, dual back pressure values and a tri-cone drill bit. A distinct advantage to the stand along unit compared to the coiled tubing unit is the ability to operate on wells were the surface pressure is greater than 3,000 psi. The HCU’s slip interlock system solves this by removing the human error factor that previously allowed the operator to inadvertently open both sets of corresponding slips simultaneously. The interlock system does not allow the current slip to open without the other slip having a true bite on the pipe and when in use, the potential for dropped or launched pipe is significantly reduced. The interlock system also notifies the operator if there is a sheared slip with proximity sensors that detect any fault in the slips and provide safe working conditions. In high pressure situations above 3,000 psi, the operator will snub, or strip, ram to ram. Previously, operators had to make the dangerous assumption that a ram was truly closed and sealed around the pipe. With ram indicators in place, this is no longer an issue as the technology notifies the operator whether a ram is completely sealed or not. The WOB can be adjusted at any time during the operation by the unit operator to account for any change in hole conditions.
Traditionally coiled tubing units have been utilized for frac plug drill outs in horizontal wells in the Permian Basin. Due to increasing well complexity operators have begun using high technology hydraulic completion units, also known as a snubbing unit, to drill out frac plugs.
Downfalls of CTU
There have been many SPE papers that review tools and procedures for coiled tubing to become more consistent and effective at drilling out frac plugs and reach further into the lateral. The objective of these investigations was to determine a better way to remove frac plug cuttings and frac sand from the lateral, while reducing sweeps and short trips back to the curve. The authors sought but could not identify any previous publications on the use of snubbing systems to drill out frac plugs. Dissolvable plug technology has developed as a possible alternative to composite plugs in extended reach laterals, but industry experience has been inconsistent at best. In a comprehensive study of Permian and Eagle ford wells, drill-out times and costs were compared between composite and dissolvable plugs
- Coiled tubing has mechanical limitations that increase risk when drilling out frac plugs in extended reach laterals.
- Beyond a certain point, coiled tubing cannot be pushed further into the wellbore without potentially buckling or damaging the string. There is also additional risk with getting stuck as cuttings from frac plug parts and frac sand are less effectively removed from the wellbore when unable to apply rotation.
Lateral lengths of 5,000 to 7,500 ft were common between 2005 and 2016 with the exceptions of the Bakken where laterals often exceeded 9,000 ft. Operators in the Marcellus shale led the way in extended reach laterals, drilling 9,000 to 12,000 ft. laterals starting in 2012. Today, other basins such as the Permian and Eagle Ford have followed suit and operators are drilling extended reach laterals exceeding 10,000 ft. to rival the Marcellus.
HCU's in Permian Basin
Drill out problems:
As lateral length increased in the Permian Basin, challenges began to arise while drilling out frac plugs with a CTU. This POP friction reducer is one of the most expensive additives on location so the more of it used, the faster the job cost increases. Since coiled tubing is unable to rotate, a cuttings bed forms on the low side of the wellbore. This creates additional friction between the coiled tubing and casing which can lead to excessive pick up weights, decreased ability to reach plug back total depth , and stuck pipe. To combat this, viscous sweeps are generally pumped after every plug and range in size from five to ten barrels in an attempt to circulate as much plug debris and sand out of the well as possible. These pockets present the potential for cross flows which can result in stuck pipe while drilling out frac plugs. These cross flows and the sticking issues associated with poor hole cleaning have resulted in multiple instances of stuck coiled tubing. On several occasions, the stuck pipe has been pulled or worked free, but has required extensive hours of non-productive time to do so and incurred detrimental costs to the project.
In a few instances, the coiled tubing had to be cut and the well worked over to try and remove the stuck tubing. Fishing coiled tubing in the lateral is a difficult and costly task. Cutting the coiled tubing and rigging the unit down from location adds an additional five to seven days and is followed by a workover rig or HCU to fish the tubing. The fishing job described above requires several weeks of operations and it is known that costs can easily surpass $1MM.
A HCU was implemented in March 2019 to drill out frac plugs in various fields of the Permian Basin in conjunction with CTUs. The following results are based on data from 2019 where /-50 wells were drilled out using the HCU and /-125 wells were drilled out with a fleet of two to three CTUs.
The HCU presented a solution to the problems encountered with a CTU mainly due to the ability to rotate the workstring which resulted in more efficient hole cleaning. The added rotation aided in more efficient cuttings transport in the lateral which in turn resulted in a major reduction in chemical usage and cost. Use of POP friction reducer, which is pumped when torque and drag values begin to trend higher than modeled, decreased significantly after the implementation of the HCU. Although there were two to three CTUs running during the year as compared to one HCU, the ratio of events is ~4:1 and total number of hours is well over 10:1. The longest NPT events are when the CTU becomes stuck and cannot work the tubing free. The benefit of the HCU was the unit was able to fish and retrieve the workstring without moving off the well or calling out another unit. As the HCU was trialed in various fields and formations across the Permian Basin it became clear it excelled in particular fields, generally those with higher pressure. While the HCU has the ability to drill out successfully in each of the fields in the Permian, there are more complex fields, that are exclusive to the HCU application. Also, a large decrease in average days to drill out in Eddy County when comparing the HCU to the CTU.
As mentioned, another benefit of the HCU is the ability to drill out and install the downhole completion equipment without moving off the well or bringing in a workover unit. This eliminates the need to rig up a workover unit to run production tubing and artificial lift. The HCU has successfully run tubing, gas lift mandrels, and a control line through the unit.
Implementation of HCUs into the Permian Basin fleet in 2019 has resulted in significant improvements in drill out metrics in many applications. The addition of pipe rotation has decreased the need for chemicals by almost one third the volume which has greatly reduced costs. The ability to install production equipment directly after drilling out the frac plugs has decreased the time from drill out to initial production by 16%. The units have proven useful for a variety of work throughout the Permian Basin beyond drilling out frac plugs. Fields with longer laterals, high reservoir pressure, or downhole complexities are being drilled out successfully and efficiently. The HCUs have proven to be a viable and cost-effective option to drill out frac plugs in high pressure and extended reach lateral wells.