You'll go away with a new tool for your tool kit!
You'll go away with a new tool for your tool kit!
The Hydraulic Fracturing and Water Management Forum entertained and answered many questions about the opportunities, problems and solutions involved in hydraulic fracturing. Some questions could not be answered due to time constraints. However all of the questions submitted regarding refracturing and expandables are answered below.
Q: Bob, how should the original propped fracture be considered in a refracture design, or how might it change the refracture’s impact?
A: Good question, the production results from the original fracture should show up in the recovery factor analysis and the remaining mobile hydrocarbon analysis should be good. Mechanically, the more the original fracture has depleted the reservoir, the larger the volume is needed for the refracture to recharge the old perfs. As we mentioned, with extreme depletion, the delta p may need to be increased.
Q: During refractures with a liner, is the isolation method used Plug and Perf? Are perfs pre treated (broken down) with acid?
A: Once the liner is expanded, the fracture is identical to a new well plug and perf. Most operators use a little acid up front, but there have been operators like Apache that have done quite a few without it. We haven’t looked at any studies that link acid use to cluster efficiency but it may be beneficial.
Q: Is there a minimum distance between a parent and child well for a pre-load? Are you injecting under the fracture gradient? And can you comment on a recommended injection rate?
A: First of all, there is no way to effectively preload the well to prevent asymmetric fractures in the infill wells unless hundreds of thousands of barrels are injected versus the most commonly used 10,000 to 30,000 bbl range. If you decide to write off the EUR in the infill well (not our recommendation) I would do a Hall plot to see where extension pressure is and stay below that pressure. You might have to reduce the rate as you pump the extension. That is a function of pressure, not rate.
As for the minimum distance before asymmetric fractures take place, if the infill well fracture will mechanically interact with a primary well depletion area, the infill well EUR will suffer badly. This is affected by cluster spacing. If you split 90 BPM fifteen ways, that is only 6 BPM going into each cluster and 1/15th of the total volume per cluster versus a five-cluster treatment, which has 18 BPM and 1/5th of the treatment into each cluster. The larger number of clusters should result in shorter fractures that won’t impact the depletion sink as quickly or as much as the larger volumes through fewer clusters. In our latest study, which we are submitting to the May Parent-Child workshop and URTEC, we are going to dig into the interference studies to get better distance criteria for where we think the infill performance is affected, and that number may come from the recovery factors themselves. I am ballpark thinking 1,000 ft is a good distance, only because one operator saw good results in the Wolfcamp with 880 ft spacing, and 15% lower performance when the wells were moved to a 660 ft spacing. There have been several papers that deal with this and we will be digging into those shortly for our current study.
Q: Bob, what is your experience of pre-loading with CO2, and can you explain some of the advantages and disadvantages of pre-loading with CO2?
A: Conceptually, pressure is pressure. The only issue is what volumes need to be pumped. One of the Eagle Ford pilots presented at DUG in September indicated that pressures were approaching the fracture gradient after 30-day huff and puff cycles. Rich gas is also an option, as is Y grade. Y grade may be better since you don’t need as much horsepower to pump as a rich gas. CO2, being a liquid, is a plus there. You may want to add some nanoparticles as well when you pump the CO2. There are a lot of examples where the Nissan type systems have been very effective in dislodging residual oil and the CO2 should as well. You might as well try and make as much as you can from the primary well production, even though the primary goal is to re-pressurize the depleted regions.
Q: Mark, is the expandable liner more popular than cemented casing?
A: That depends on the application. However, conventional applications seem to be the most utilized.
Q: Mark, how many continuous ft of expandable liner can you run?
A: Regarding refractures, it is application-dependent on whether it is a vertical or horizontal refracture.
Q: What is the longest run you have made?
A: The longest single run we have made in a horizontal well is 5,200 ft. The longest “total reline” we have run is 10,000 ft.
Q: How many expandable liners have you run?
A: We have done 2,239 expandable installations overall (155 in 2019) and 52 horizontal refracture liner installations.
Q: Mark, what are some technological risks to running expandables that we wouldn't encounter with a cemented liner?
A: Debris in the hole while expanding. While hole cleaning is critical in both expandable and cemented liner applications, there is a greater risk while expanding versus cementing a liner.
Q: In what basins have you run expandable refracture liners?
A: We have run refracture liners in Eagleford, Permian, Marcellus, and Mid-Con.
Q: Can you run standard or “off-the-shelf” plugs in your post-expanded liner?
A: Yes, there are many plugs available that will set in our post-expanded ID.