Plug & Perf: Drill-out Fluids

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In my last article, here, I discussed the systems and procedures used to drill out plugs, mostly from a mechanical tool perspective. After publishing the article there were a few comments regarding the use of gel sweeps during the drill up. Some readers didn’t believe in their value while others felt it was a best practice. Having spent most of my career on the completion tool side, I was ignorant about the chemical systems used, how they work, and what is done in the field.

I took this opportunity to reach out to my friend Kevin Cunningham who is a project manager and business development manager for Binder Science, LLC, one of the leading providers of performance chemicals in the oil industry.

Drill-out fluid systems

The fluid used during a drill out operation serves two purposes. The first is to power the mud motor that rotates the mill or bit used to mill up composite plugs. The second use for fluids during the drill out operation are to help lift the cuttings from the well once the plug has been milled through. During the drill out operation the fluid, mostly water, is pulled from a frac tank, passed through a blender that can be used to add in chemicals, and is then pumped through the coil/stick pipe down through the milling bottom hole assembly (BHA), and is then circulated out. When it comes out of the well it will pass through a screen or plug catcher to capture the larger debris and this is returned to the frac tank.

To aid in this operation, chemicals are added to the fluid. The major chemicals used for these purposes are Friction Reducers (FR) and Viscosifiers (Gels). Other chemicals such as lubricants, scale/corrosion inhibitors, biocides, scavengers, etc. are also added but for other tertiary reasons. 

Cuttings removal is the most important function for reducing risk of the intervention. Composite plugs contain several different materials, if you’d like to know more about them, I wrote an article here. These components have a specific gravity greater than water as follows:

With densities greater than water, removal of the debris after drill-out is reliant on the fluid flow and characteristics. 

Turbulent Flow

There are two states of flow when a fluid is flowing: Laminar and Turbulent. Laminar is characterized by smooth flow paths where all the fluid particles are flowing in the same consistent direction. Turbulent flow is characterized by irregular flow paths that create tiny whirlpool regions. A dimensionless calculation, the Reynolds Number, is used to determine laminar vs. turbulent flow.

The higher the Reynolds number, the higher the turbulence. As you can see there is a direct relationship with velocity, density, and flow area and an indirect relationship with viscosity. 

The goal of the operation is to keep the flow as turbulent as possible with changes to the viscosity and the velocity. Turbulent flow is better at carrying out debris because of the irregular tiny whirlpools created in the flow. Without the amount of turbulent flow required for the cutting size/weight, the cuttings will fall out of the flow and migrate to the bottom of the well. As the cuttings “ball” up in the wellbore, there is an increase in getting the coil/stick pipe assembly stuck during the operation.

Friction Reducers (FR)

The pump, surface piping (or iron), the coil/stick pipe, and BHA will have pressure ratings. For instance, combined as system, they could be rated for 10,000 psi. For safety reasons, the operator and service company may limit the allowable pressure on the system to 8,000 psi. Pumping the fluid, down through thousands of feet of pipe/tubing, a BHA, and then circulate out of the well requires pressure.

The max operating pressure dictates the maximum flow rate and thereby fluid velocity available to power the bit and aid in cuttings removal. A high velocity in the return fluid is necessary to maintain turbulent flow and the right conditions for carrying out the debris left from the milling operation.

The head loss from the tubing and equipment may cause the pressure needed to achieve the required flow velocity through the system to be higher than the equipment will allow. To help with this, the service company will add FR to the fluid.

The FR will reduce the friction caused by the system and enable higher flow rates at the same pressure drop. For instance, without FR you could achieve 10 bbl/min at 8,000 psi and with FR you could get the same 10 bbl/min at 6,000 psi. This will allow the flow rate to be increased, without exceeding the pressure rating of the system.

As the pressure required to maintain the desired flow rate starts to increase towards the limit, during the operation, the service company will mix up a batch of FR in the blender tank and then introduce it to the flow of the fluid. Additional FR will be added to the system, throughout the operation, to maintain the proper concentration of friction reducer.

The major FR used in coil/stick pipe operations are polyacrylamide based, which is a water-soluble polymer. The polymer chains can be low to high molecular weight and charge density to provide different levels of performance. Some high viscosity friction reducer can also be used as a gel sweep when applied in higher concentrations.

Viscosifiers (Gel Sweeps)

In addition to maintaining the proper turbulent flow, viscosifiers, or gel sweeps, can be used to help remove the debris from the well. In this process companies will pump a 5-10 bbl “pill” of higher viscosity fluid at regular intervals. Though the viscosity of the fluid has an indirect relationship with the Reynolds number, i.e. higher viscosity results in lower turbulence, the higher carrying capacity of the gel sweep aids in cleaning. These sweeps are usually employed after one or two plugs have been milled through.

The primary viscosifier used is Xanthan Gum. It is 3x more effective at viscosifying the fluid than Guar Gum. It also has better properties at higher temperatures and in the presences of acids and salts than Guar and other options.

When pumping a 5-10 bbl sweep through the annulus between the coil/stick pipe this fluid can stretch across a long section of the well. For instance, assuming 5.5” casing and 2-5/8” coil results in a 5 bbl sweep stretching 300’ across the well and a 10 bbl sweep being 600’. The goal is for these long stretches of higher carrying capacity fluid to catch any debris and circulate it out with it.

Success

In my last post, I had a few comments stating that they would no longer use Gel Sweeps and would manage the cuttings by cutting FR. If the equipment in use and the well being drilled out provides enough annular velocity to keep the turbulence of the flow enough to carry out the cuttings without the use of Gel, that’s a great practice. If, however, the fluid velocity along isn’t able to achieve this goal, other practices have to be employed.

As with most things in the oil industry, you cannot assume a one size fits all methodology will perform the same on every well. Having a solid best practice is the first step to a successful drill out, but active feedback and monitoring of the practice must be done. If the procedure isn’t generating the proper amount of debris returns, then changes to the procedure must be made to ensure success.