Capillary-Injection Tubing Anchor Optimizes Treatments, Monitoring

In nearly every well’s producing life, artificial lift will be needed to extend operation and maximize reservoir recovery. However, the efficiency of any artificial lift method is hampered by myriad costly problems, including corrosion, scale, paraffin and salt deposits that can lead to premature failure of the lift system. Without a means of effectively pumping the right treatment chemicals precisely where they are needed, the risks of workovers and lost production rise, threatening the economic viability of the well.

Capillary injection is a popular method of downhole chemical delivery that can extend the production interval between workovers provided that the capillary string can reach far enough downhole to be effective. The typical tubing anchor used above the downhole pump often hinders the deployment of the control lines.

Conventional tubing anchors have to be rotated nine to 12 turns to set, which might limit the installation of control lines to above the anchor because the risk of crimping or breaking the lines is too great for the operator to accept. Delivery of chemicals such as corrosion inhibitors, scale inhibitors or foamers is therefore limited to above the anchor, leaving all tubing below the anchor exposed to untreated wellbore fluids.

Reducing turns to set

Weatherford developed a solution to this challenge in the form of a capillary-injection tubing anchor that allows the control lines to pass through the anchor via a bypass channel. This channel, which can accommodate either ¼-in. or ³/₈-in. control lines, lets the string reach the inlet of the downhole pump for delivery of the entire chemical treatment. This targeted chemical delivery often results in a significant reduction in chemical treat rates to achieve the desired level of protection for the tubing and rods.

The new tubing anchor sets and unsets in just one-quarter of a full turn as opposed to the multiple turns required for the traditional anchor.

Improving downhole sensing

The new tubing anchor also has been successfully deployed to improve real-time monitoring below the anchor. The anchor’s bypass channel allows control lines for a range of downhole sensing tools to be deployed below the anchor and tied into a gauge at the pump intake. The control lines can be installed at the same time as the chemical injection lines using the same capillary crew at the rig site for additional time and cost savings.

The quarter turn to set the anchor reduces the risk of sensor failures due to a kinked or broken line. It also lowers the risk of breaking bands used to hold the lines to the tubing. Broken bands could fall to the bottom of the well and plug or foul the pump, the anchor or the injection valves. This may require a fishing job to remove the band debris from the well.

The ability to monitor real-time pressures and temperatures below the tubing anchor affords optimization opportunities for the artificial lift system. Measurements of the hydrostatic pressure at the intake of a rod pump, for example, serve as input to the pump’s variable frequency drive (VFD). The VFD then adjusts pumping rates based on the hydrostatic pressure, maximizing pump efficiency and minimizing the risks of overloading the rods or burning out the pump.

The data collected by the real-time monitoring systems not only help the operator make decisions to maximize production but also inform the decision on the optimal lift method for a well. An operator accustomed to using gas lift on each well may be inclined to change to another lift method if the downhole data suggest that an alternative form of lift can improve production and deliver a quicker return on investment.

Optimizing chemical injection in Permian Basin wells

The new tubing anchor design was first installed for an operator embarking on a new drilling campaign in the Permian Basin in 2012. While the new wells were drilled in a region that promised an EUR of 71%, these wells also had higher failure rates compared to older wells in the operator’s nearby assets.

Higher fluid levels in the wells for longer periods of time translated to increased rates of corrosion-induced failure. The operator was forced to inject up to 5 qt/d of weighted corrosion inhibitor (at a price of $25/qt), but this was insufficient to keep corrosion rates low enough to avoid frequent leaks and rod failures, particularly in lower sections of the well below the tubing anchor.

Residual chemical returns were between 0 ppm and 15 ppm, well below the operator’s target range of 55 ppm to 60 ppm. Every one to two weeks, new wells were being shut in for at least three days to repair or replace corroded equipment at an average cost of more than $25,000 per pull. The operator was forced to make a minimum of two pulls per year on each well in the first year of operation. This translated to an average annual operational cost of more than $95,000 per well.

The operator called on Weatherford to replace the conventional tubing anchors with the new quarter-turn anchor. The new anchors were effectively set by rotating by just one-quarter to one-half of a full turn at surface, minimizing the risk of damage to the chemical injection cap string. In addition, the chemical injection point was placed farther downhole adjacent to the pump intake, allowing the operator to switch to a lighter and more cost-effective corrosion inhibitor that was injected at a rate of 1 qt/d.

Two days after the wells were brought back into production, residual corrosion inhibitor readings were between 66 ppm and 68 ppm and have remained within that range. This indicated that the pump intake was effectively introducing and distributing the chemical into the produced fluid stream to protect more of the rod and tubing string between the intake and the surface.

The first wells installed with the new tubing anchor have been running for more than one year with no pulls. In addition, the shape of pump cards did not change outside of normally expected well production decline. This provided further assurances that the rod-pumped wells were not experiencing the corrosion-related problems that had plagued them previously.

The fact that no workovers were required, coupled with the switch to a less expensive chemical treatment, lowered the average annual operational costs for each well to under $19,000 for a savings per well of nearly $77,000 in the first year alone.

The operator has since placed the capillary-injection tubing anchor in more than 20 of its wells in the field, and Weatherford has deployed the new system in more than 100 total wells in Texas and the U.S. Rockies.