OKLAHOMA CITY ─ The industry is taking more of an interest in coiled-tubing completions with cemented liners, according to remarks at Hart Energy’s DUG Midcontinent conference and in additional industry reports.

For example, Whiting Petroleum Corp. has reported strong production in tests of the technique in the Middle Bakken and in the underlying Three Forks benches, according to Oil and Gas Investor’s March cover story, “Bakken, Not Beaten.” The formations are each roughly 30 feet thick and the rock is mostly dolomite and dolostone.

Barry Dean, senior production-stimulation engineer, Schlumberger Ltd., told DUG Midcontinent attendees, “if your objective is to surgically go in there and get every, single cluster active, it is a viable solution.” He added that the technique may be particularly helpful in narrow formations that have at least slightly higher permeability than shale, such as sandstone. “The frack height is pretty small … There is a place for it as perm goes up and reservoir thickness goes down,” he added.

Hap Pinkerton, technical-services advisor, Halliburton Co., said, “It is a great technology.” It’s not inexpensive, “but you do pick up efficiency.”

Stephen Roberts, senior vice president, drilling and completions, for Jones Energy Inc., told attendees that the company experimented with cemented-liner/sliding-sleeve/coiled-tubing fracks last year in more than 40 wells in its Cleveland-sandstone play in western Oklahoma.

Jones has drilled some 400 horizontals in the Cleveland, beginning in 2004. Initially, completions were a few stages, openhole. That grew to 12 stages and then 20 stages. In 2013, it went to 60 stages using the plug-and-perf method. It then employed the coiled-tubing frack with cemented liner and sliding sleeves.

"It was relatively new technology … The interesting thing with this technology is it allows you to optimize spacing. It is one of the first technologies ever like this in the hole. What it allows you to do post-frack is determine how many of the fracks you pumped actually communicated with the prior frack,” he said.

With this data, Jones was able to settle into a number of stages best for its Cleveland program. “It was not 60; it was not 43. In the Cleveland formation, it is 33.” Jones has switched back to openhole completions, using that number. “This time, the openhole system is much faster, much more cost effective … That’s where we are today.”

The 60-stage, plug-and-perf wells produced 40,000 barrels in their first year. Early results on the 33-stage, openhole completions have a similar IP and decline curve to date. The new openhole wells cost about $3.8 million each, drilled and completed, in December. With reduced oilfield-service costs at the current oil price, new wells are costing about $3 million each. The company aims to reduce that to $2.6 million, “and we will,” he said.

Other Trials

Calgary-based, micro-cap Kicking Horse Energy Inc. has used the coiled-tubing technique in the Montney play in western Canada, according to an archived company report on its trials. It cited that its challenges with plug-and-perf included that, at a well depth of more than 11,000 feet, plug-pump-down time was four to six hours and sand-offs were a problem. It added that it was able to capture downhole-pressure data during the coiled-tubing fracks, which proved isolation between stages and helped optimize future operations.

Meanwhile, Whiting continues to experiment with the coiled-tubing/cemented-liner frack in the Williston Basin—and producing enormous wells. It reported in October that its Flatland Federal 11-4HR (Middle Bakken), 11-4TFH (Three Forks 1) and 11-4TFHU (Three Forks 2) in McKenzie County IPed 7,120 BOE, 7,824 BOE and 5,930 BOE. The first was completed with a cemented liner and coiled tubing in 94 stages; the second, with cemented liner and coiled tubing in 104 stages; the third, with plug-and-perf and five frac clusters per each of 30 stages. The completed cost of each was roughly the same—between $8- and $8.5 million.

Jim Volker, Whiting chairman, CEO and president, said in an earnings call earlier in 2014 that the effectiveness of each frac stage is better understood with the coiled-tubing technique. “When you open that port up, it has to go out there. You’ve got cement behind the pipe. There’s nowhere else it can go but out into the formation … We can tell by our pump schedule, essentially, exactly how much frac volume is going out in each of those perforations. So there’s no guesswork involved. It’s pretty direct.” (Source: Transcript, SeekingAlpha.com.)

This past month, Whiting reported that in the Sand Creek Field northeast of the Flatland wells, it completed three Tarpon Federal 24-20 wells in two days in December. Its 1H came on with 6,234 BOE; its 1RTF, with 4,818; and its 2RTF, with 4,105. Details on the completion design were not provided.

In the subsequent earnings call, Mark Williams, Whiting senior vice president, exploration and development, said that “we’re really sort of at an inflection point … What’s really driving it is how we’re distributing our stimulations around the wellbore so a lot more entry points, which is accommodated by cemented liners that we’ve been using.”

Adding in trials with slickwater fracks, “that’s just allowing us to reach out and touch the reservoir a whole lot better than what we were doing previously,” he said. (Source: Transcript, SeekingAlpha.com.)

Its Waldock Federal 14-4-3XH was completed with coiled tubing this past spring. In the well’s first 154 days online, it made 90,864 barrels by year-end 2014. It had IPed 365 barrels. November production averaged 834 barrels a day.

David Deckelbaum, senior E&P analyst, KeyBanc Capital Markets Inc., reported after the Whiting earnings release in February that “…various completion initiatives, such as further use of cemented liners, slickwater fracs and coiled-tubing completions, could create another $6/share to (Whiting’s net asset value) in aggregate."

Nissa Darbonne is the author of The American Shales. Contact her at ndarbonne@hartenergy.com.