Tailpipes Through The Bend Of A Horizontal Well Improve Production And Are Becoming A Standard Practice For Unconventional Horizontal Wells
Artificial lift systems under-perform when faced with unstable slug flows from a horizontal wellbore. Slug flows bring solids issues and pump gas interference which increases operating expenses from poor runtime, excessive workover costs, and inadequate production drawdown.
Five years ago, the HEAL System was developed by a producer to address slug flow challenges. Its capability to provide desired production drawdown with artificial lift system reliability has improved horizontal well production performance in hundreds of wells in all the liquids producing basins in Canada and the United States. Key to its success has been an engineered small internal diameter tailpipe positioned in the bend section of a horizontal well. It is important to note that the average internal diameter of these tailpipes is only 25.4mm or 1 inch. Operational low risk placement of such a small internal diameter tailpipe into a bend section was resolved by mechanically suspending small diameter tubes inside conventional robust production tubing.
During this past year and contribution from Schlumberger’s considerable resources, HEAL Systems has undergone important downhole tool redesign upgrades. Such upgrades have resulted in lower cost and risks, as well as improved reliability.
Testimonials from several producers benefiting from the HEAL System are as follows:
Effectively Producing High GLR Wells
“Mancal had been exploring new ways of unloading liquid rich gas wells and decided to try the HEAL system. The candidate well had been on a continuous plunger system with a liquid gas ratio (LGR) of 60 bbls/mmscf. The well had depleted to a level in which any fluctuation in surface line pressure stalled out the plunger and a swab rig was required to restart the well. Conventional pump and rods had been installed on the well prior to the HEAL system, however was unable to pump the well due to severe gas interference. The HEAL system was installed and the production of the well actually exceeded the previous rates by 60% from when the well was on continuous plunger and was able to efficiently pump at a gas liquid ratio (GLR) over 3,000 m3 gas/m3 fluid. Starting the well up now is as simple as starting up the pumpjack.”
Darron Mazurek, P. Eng., Sr. Production Engineer, Mancal Energy Inc.
Figure 1. Production data for Mancal showing HEAL enabled rod pump at a very high GLR
Fluid Conditioning to Resolve Slug Flow
Difficult to produce, high GLR wells in the Muskeg of northern Alberta also brought Strategic Oil & Gas to the attention of HEAL.
“For many of our wells we weren’t able to hit our expanded type curve rates due to high workover frequency and gas locking. Using HEAL on many of our wells on both rod pump and ESP has allowed us to produce at higher rates and understand our well potential more easily. We also worked with HEAL to co-author a technical paper showcasing the improvement in slug flow mitigation when you condition the fluid around the bend.”
Kevin Eike, Manager Production & Field Operations, Strategic Oil & Gas
Figure 2. Production data for Strategic showing how fluid conditioning mitigates slug flows (URTeC 2670789)
Pump Placement in Difficult Wellbores
As pad drilling continues to become more common, it often leads to difficult drilling profiles based on surface location limitations combined with specific intermediate casing point (ICP) targets. In these cases, it can be very difficult to effectively artificially lift these wells without severe side loading and hole in tubing issues when rod pumping is required. For Torxen, their new wells in the Basal Quartz faced this exact issue.
“We had a few wells where we just could not land the pump at 70 degrees and expect to produce the wells. With a HEAL PSN landed some 250m higher, we avoided high DLS areas, while saving on rods and tubing while also limiting the planned jack loading. In this case we could also produce the wells efficiently at a GLR greater than 300 m3 gas/m3 fluid and avoid early time solids production issues.”
Kevin Wetteskind, Production Engineering, Torxen
Figure 3. Wellbore image for a Torxen well (courtesy 3Dwellbore). Red line is HEAL PSN placement, some 250m above the typical tangent at 70 degrees (blue line), with severe DLS sections above in hotter colors.
Reduce Operating Costs from Workovers
“Broadview has used 2 HEAL systems in rod pump applications. Traditionally, certain wells in our Wainwright Sparky field have had high workover frequencies related to solids production and gas slugging. With the HEAL System in place we’ve had no artificial lift repairs which is very different from offsetting wells. These costs savings combined with no lost time due to production issues has more than paid off the installations.”
Ian Langdon, VP Development, Broadview Energy
Warren Tippett, Senior Advisor, Broadview Energy
Darcy Spady, Advisor, Broadview Energy, SPE International 2018 President
Increased Production and Cash Flow
“To help deal with the slugging and maintain steady inflow on gassy and foamy production from our Charlie Lake wells, we’ve used 3 HEAL Systems that have helped to generate over 25,000 boe of incremental production in their first 100 days since installation. We see great value in landing the PSN higher with the HEAL system in wellbores with complex geometry to reduce loads and increase drawdown rather then working over the well to lower the pump and fight rod break issues.”
Dave Erickson, VP Operations, Longshore Resources
Mark Tuturea, Production Engineer, Longshore Resources
Figure 4. Longshore log decline analysis with HEAL Systems provided greater incremental production
By improving gas separation, it becomes easier to reduce fluid levels above the pump, and by providing a low flowing gradient below the pump with our Sized Regulating String (SRS), a drawdown improvement results in production uplift. ARC Resources was also able to showcase the production uplift from one of their multiple HEAL installs in their Montney, Ante Creek field. This result led to a larger multi-well Montney case study that showcased a 75% uplift in the Montney wells reviewed. To complement a dominant early lift type used in the Montney, HEAL has also successfully shown a gas lift case study to demonstrate how reducing standoff and slug flow adds tremendous benefit.
Figure 5. ARC Resources production data from a HEAL install in their Montney Ante Creek field (courtesy ARC 2016 Investor slides)
With today’s challenging economic conditions, production optimization with the HEAL System is a very cost-effective way to save on capital, reduce operating costs and increase production. Please visit www.healsystems.com to learn more and send us a data sheet to see how much value we can add to your wells!
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