Refracturing Success Demands a Better Understanding of Failures

By Stephen Rassenfoss 7 Jul 2014

Refracturing older unconventional wells is likely to reward those willing to seriously investigate the reasons behind production declines and what can be done to restore them, according to George King, distinguished engineering advisor at Apache Corp. King’s comments were part of a free webinar called Re-Fracturing: Timing, Prerequisites, Diversion and Application, broadcast in June.

“We are going to have to look for better ways of fracturing initially and (then) refracturing these wells,” King said. The immediate reward would be finding the best method for identifying wells that are likely to respond to treatment and developing cost-effective techniques to deliver it. Longer term, what is learned from the shortcomings of old wells can be used to improve the performance of new ones.

The practice of refracturing has demonstrated the value of correcting past mistakes. A look at 13 wells refractured in the Barnett Shale found that, on average, they returned to their initial production rate and added 0.5 to 1 bcf to their estimated ultimate recovery (EUR), King said. A Devon paper (SPE 154669) on the wells put the average cost of the restimulations at USD 900,000.

Early refracturing projects were designed to correct the errors made during the trial-and-error process that developed the techniques now commonly used to exploit shale formations. Many were vertical wells with only two stages for hydraulic fracturing. The gelled fluids used at the time damaged the formations and created relatively short fractures. 

When Devon Energy refractured those 13 wells, it expanded the number of stages to three, used more sand to prop open the fractures, and pumped slickwater to create larger, more complex fractures using a fluid formula with a minimum of chemicals. According to the paper: “Initial results were mixed, but the economics have gradually improved by developing candidate selection criteria, and modifying the simulation design to contain costs.” 

That quote could be applied to the industry’s refracturing efforts in general. Results are mixed, well selection is critical, and cost-effective methods for diagnosing and addressing problems are equally critical. Adding to the challenges has been the industry’s rapid shift to liquids-rich fields using horizontal wells, many more stages, and improved methods based on years of experience.

The combination of new plays, such as the Bakken and the Eagle Ford, and new technique to exploit them raises a new round of issues for the industry to consider, King said. Refracturing interest in those plays is growing as wells reach the age where production has declined to the level where refracturing becomes an option.  

Based on past experience, success will depend on the wells chosen and the ability of companies to identify problems that can be economically remedied. While production from most shale wells declines steeply, the reasons for it vary, and those reasons can be the difference between success and failure when trying to revive an older well.

Refracturing a well where the problems are due to the rock is not going to pay off. Often, failure in refracturing indicates that “there was not enough work on how much of the reserves are left to be recovered,” King said.

Geologic problems could be blamed on sections of the reservoir isolated by a fault, rock lacking adequate conductivity, or production lost to another well nearby, he said. Problems in the ground that limit production are common. He pointed out that in many wells with regularly spaced fractures, only 50% of wellbore was really contributing. “We are wasting a lot of energy and money fracturing all of the wellbore when some of it didn’t have much potential to begin with,” King said.

Where reservoirs are producing, analyzing the output over time can be useful. King said a change in the ratio of gas-to-oil production over time can be an indicator of changes in the well. A rising gas-oil ratio may well indicate the fracture network is shrinking, providing enough space for natural gas flow but not for oil production.

Generally speaking, that problem can be treated by using hydraulic pressure to reopen fracture networks and pump in stronger, long-lasting proppant. But when it comes to the details on how to do so, practical advice is limited. There have been few SPE papers evaluating large numbers of wells successful wells, and even fewer analyzing failures, said King.

King was peppered by questioners with practical concerns: what is the best method for fluid-diversion techniques to use, how to pressure old well bores to ensure they can stand up to refracturing, and whether to use perforations or create new ones. He offered thoughts on that wide range of topics, but warned that many questions have yet to be answered.

A company considering a significant refracturing program, on the order of 100 wells, should consider creating a team of professionals, King said. “The learnings from that would cover cost many times over,” he said. 

There are wells where a refracturing job would stand out as a technical achievement. “With refracting, you are at the mercy of what is in the well,” King said. “The first completion is going to be the easiest. Redos are going to be more difficult requiring some thought and probably development of new tools.”

As companies become more interested in going back into wells, that could alter the decision-making process when completing new wells.  “The best completion is the one that gives you the best flexibility with refracturing,” King said. That line of thinking can offer support for wider diameter casing and plug-and-perf completions.

And it may be wise to start with relatively modest steps. King suggested using coiled tubing to deliver a relatively low level of hydraulic pressure to clear out near well-bore obstructions, and a straddle packer to isolate the zone while doing so.

“Try putting a straddle packer on coiled tubing and go to each perforation cluster and hydraulically fracture it using high-quality proppant,” King said to listeners on the call, adding, “the few I have seen that have not worked all that well may indicate a reservoir problem rather than a completion problem.”

Stephen Rassenfoss is the Emerging Technology Senior Editor for the Journal of Petroleum Technology.

Further Reading

SPE 134330: Refracs: Why Do They Work, and Why Do They Fail in 100 Published Field Studies?Mike C. Vincent, Insight Consulting.
SPE 154669: Barnett Shale Horizontal Restimulations: A Case Study of 13 Wells, Mark Craig and Steven Wendte, Devon Energy, James Buchwalter Gemini Solutions.
SPE 168607: Re-fracturing Horizontal Shale Wells: Case History of a Woodford Shale Pilot Project, S. French, J. Rodgerson, and C. Feik, BP America Production Company