Plug & Perf: Drill Up Systems
After a composite plug has been run and frac’d against it must face its last challenge; the drill up. The final step in the Plug & Perf completion requires the removal of all the plugs, sometimes more than 100, from the well. This is done by milling them out, which is why the plugs are made of composite to start with. The goal of the drill out is to drill the plugs into small pieces that can easily be removed from the well by the drilling fluid. And, complete the operation as quickly as possible. There are two systems used for drill out: coiled tubing and stick pipe. With each system there are downhole tools and processes that allow them to complete the operation.
Drill Out Systems - Surface
Coiled Tubing
Coiled tubing is a long coil of continuous pipe that can be unwound into the well. Coiled tubing is a faster operation because it can be quickly unspooled into the well, without the need to thread joints together. It is limited by its inability to rotate, large annular area, and very low ability to transfer weight to the bit. Coiled tubing is generally smaller than stick pipe (2-5/8” vs. 2-7/8” in 5.5” Casing) resulting in reduced annular fluid velocities around the tubing during the drill out.
Stick Pipe
Stick pipe is jointed tubing that is run into the well and connected with upset connections, such as PH6. The stick pipe is run using a workover rig and a power swivel for rotating the pipe. Though the stick pipe operation is slower, due to having to connect the pipe joints, having the ability to rotate the pipe provides several benefits. Rotating the pipe breaks the friction and reduces buckling of the pipe laying on the bottom of the well, this allows for transferring more weight to the bit as well as sliding further into the lateral. Rotating also provides agitation to the fluid and debris around the pipe, reducing the chances of getting stuck. The larger pipe reduces the annular area between the OD of the pipe and the ID of the casing, this increases the fluid velocity through the annulus. Higher fluid velocities will be better for carrying out the cuttings from the plugs being milled out. Another benefit of drilling out with stick pipe is that the workover rig is on location after the drill out, so production tubing/completion can be run immediately.
For high pressure applications the stick pipe will have to be snubbed into the well. Snubbing allows the well to stay under pressure when running pipe. This slows the operation down further when compared to Coiled Tubing. Coiled tubing is run in a way that high/low pressure situations do not affect how it is run.
Drill Out Systems – Downhole
Coiled Tubing
For coiled tubing drill outs the bottom hole assembly (BHA) will generally consist of the following:
Coiled Tubing (CT) connector
Back Pressure Valve
Hydraulic Disconnect
Jarring system
Circulation sub
Vibratory Tool (or extended reach tool)
Motor
Bit
The CT Connecter allows the BHA to be connected to the end of the toil. The Back Pressure Valve enables a specific hydraulic head to be maintained in the coil, it provides a “back pressure” to ensure the coil remains filled. A Hydraulic Disconnect provides a means for the coil to be disconnected from the BHA hydraulically, this is if the BHA becomes stuck. If needed the disconnect is activated by dropping ball and applying pressure to the ball on seat, which release the coil.
A jarring system is run to provide shock to the tool if it becomes stuck, this can be done with a traditional coiled tubing jar or with a tool called the HydraShock, provided by Tenax Solutions. The Circulation sub controls the flow of the fluid through the coil. It will direct flow down through the motor or out into the annulus of the coil. This allows the operator to pump more fluid than the motor requires so that more fluid is directed to the annulus. This additional flow will help to increase the velocity of the fluid and its ability to remove the composite plug cuttings. The Vibration tool, or extended reach tool, vibrates the coiled tubing to reduce the friction of the BHA on the well. This increases the system’s ability to reach deeper into the longer laterals. Finally, the fluid pumped through the coil operates the motor to rotate the bit.
Stick Pipe
For stick pipe the rig will utilize a power swivel on surface to provide rotation of the entire drill string. Downhole the drill string will sometimes include a motor and then the bit. While sometimes a motor is not used, the addition of a motor increases the velocity of the bit and can help with reducing cutting size. Utilizing stick pipe reduces the need for jars or circulating subs because the pipe can handle much higher pulling forces. The size of the pipe reduces the annulus size (increasing annular fluid velocity).
Experience
In my experience, stick pipe drill outs outperform from a cutting size standpoint. I believe this can be attributed to the violence created down hole from the rotation of the pipe. With coil you’re relying on the motion created by the motor to mill out the plug. Once the cutting pattern is established the motor alone can create a very uniform and smooth milling of the plugs. This can allow larger pieces to get past the bit during the milling operation.
Drill Out Procedures
Regardless of what system is selected for drill ups the procedure used will determine the success of the job. These determine how well the cuttings from the drill up are removed from the well. If the cuttings are not being efficiently removed, they will build up in the heel of the well and cause issues with running and pulling the tubing that contains the drilling equipment. The procedures followed during the drill up with respect to short trips, fluid flow, gel sweeps, and drilling speeds should be optimized and monitored for providing be best cleaning operation.
Cimarex published the work they’ve done to optimize their drill out procedure in 2016 through AADE. The study can be found here. The premise of the study was that they spend a ton of time optimizing their well drilling procedures and very little on plug drilling. Prior to the study, they were getting stuck with coil 5% of the time. When they applied science to their procedure, they were able to greatly reduce the risk associated with the operation, at the time of the publication a 100% reduction in stuck pipe incidents. When you read the presentation, it’s clear that the lessons learned were implemented to increase the cleaning of the wellbore during the operation. Optimizing the fluid program, reducing the cutting size by limiting mill speeds, controlling running speeds, and procedures to verify the cleanliness of the wellbore.
I’ve experienced completion engineers choose not to use gel sweeps, monitor cutting returns, and manage drill out speeds. It results in stuck coil. Unfortunately for the plug provider, they’re to blame.
What Cimarex is now doing is what I recommend. Have a set process focused on cutting size and removal optimization. On top of this have the crews monitor the success of the process. Every plug will have some different characteristics, so depending on the actual job some of the parameters will need to be adjusted.
There are pictures every week on LinkedIn of a drill up in process. In many of them, it shows the debris from each plug isolated and labeled on the ground. This is a good practice for reviewing cutting size, as well as how much debris is returned from each plug. Using this information, the process can be adjusted for optimal performance.
Summary
When there are several tools for a job, such as drilling out a wellbore, there are pros and cons for each choice. There may even be a best choice. However, how you use the tool determines how successful the job is performed. Most of the plugs on the market have been run and drilled out successfully thousands of times. If there is an issue on a drill up with one of these plugs, it may be the plug providers fault, however it can also be how you’re using the tools to drill them out.