TULSA, Okla. – Improved efficiency does not require large-scale changes to lead to cost savings and positive impacts on operations in shale plays of the Midcontinent.

Speaking during Monday’s technology panel at Hart Energy’s DUG Midcontinent conference in Tulsa, Okla., panelists explained how pad drilling combined with other changes can do just that. But obstacles remain as operators look for ways to maximize recovery.

In the last couple of months PetroQuest Energy has witnessed more efficient drilling performance in the Arkoma Woodford, primarily due some favorable attributes of the formation and technology.

“When you move to multiwell pad drilling, it doesn’t take very large changes to make great differences,” said Mark Castell, vice president, Oklahoma assets, for PetroQuest Energy. “We quickly moved from being able to drill the curve going from the vertical section into the horizontal section and then into the lateral with one assembly. That was accomplished some times in the past, but just the ability for us to do that on a consistent basis -- you don’t have to pull out for an extra trip once you land the lateral. That one has been a huge savings.”

Apply the process on a five- to six-well pad, then “all of a sudden you’ve saved eight days just with a simple directional, assembly-type change,” Castell said.

For Newfield Exploration, cost savings were realized after learning that tighter perforation cluster spacing resulted in better wells. Additional performance improvements involved the use of adjustable switches for perforating, said Valerie Mitchell, general manager for the company’s Midcontinent business unit.

“For every 18 runs we would have one misfire with traditional wireline perforating,” Mitchell explained. “Then when we moved to adjustable switches, we were able to achieve 40 runs before we had a misfire. In some cases, we had a vendor that did 243 runs without a misfire. That is really a game-changer for us.”

But other techniques are still being tested. Although plug and perf completions dominate in the Midcontinent, panelists agreed that using sleeves could be advantageous when tapping certain plays in the region, particularly the Mississippian Lime where there is more permeability, better rock quality, and perhaps hydraulic fracturing at lower pressures.

Some of the challenges with sleeves, Castell pointed out, are with larger, high-pressure type jobs. He noted that in the last year there have been large steps forward with many different types of sleeve assembles; however, plug and perf seems to be more reliable at this time.

Mitchell added that Newfield found that sleeves don’t pressure test very well, but companies are continuing to make improvements. So it’s a technology that is still being tested by Newfield. “But we think it can make a huge difference in the Meramec play or other Granite Wash play,” she said.

Although use of sleeve completions, which is widely used in Canada, is low in the Midcontinent and operators rarely use techniques such as zipper fracturing, a process in which fracturing is alternated between two wells with wellheads on the same pad, other completion tools and techniques – including batch completions – are routinely being carried out. But the results point to more complexity in some instances.

“The completions side of our industry is one where we have had a lot of growth in my opinion in terms of technology. … We routinely are running microseismic on our hydraulic fractures, radioactive tracing, chemical tracing, running production logs,” Castell said. “We’re fairly routinely performing horizontal well logging. When you put all of that together and take a look at the data that you’re getting, in general the trends that we are seeing is a much more complex system.”

The industry has a lot of growth potential. Answers to questions such as “What is driving hydraulic fracturing performance at individual stages? Why are certain stages performing better than others in an individual well?” are needed. Finding solutions is key to maximizing the frac efficiency in completions, Castell said.

“Everyone is trying to figure out what that secret solution is to completing wells and getting maximum recovery,” Mitchell added.

The future will likely hold more refracturing of wells. Castell called it the renaissance of refracing. “I think you’re going to see more of it with time as we get into the later life of shale plays and the rates are dropping off,” he said.

But it is difficult to find the right candidate for refracs, Mitchell cautioned, noting Newfield – working with BP – has done two refracs in the Arkoma basin with limited success.

Newfield has found refracs beneficial for pressure maintenance in the Anadarko Basin. For example, if Continental wants to drill a well offsetting one of Newfield’s wells that has been producing for six to 12 years, refracs are used to repressure the well so Continental’s fracs don’t knock Newfield’s offline, Mitchell said.

“It provides pressure maintenance and we haven’t lost reserves,” she said.

But the next big thing in oil and gas could be stacked formations like in the Anadarko Basin and down spacing, said Richard Mason, moderator of the panel and chief technical director for Hart Energy.

“While the Eagle Ford and Bakken have gotten all of the headlines of late in resurgent U.S. oil production, certainly one of the most unexpected developments since the arrival of the unconventional era a decade ago, the Anadarko Basin and other stacked formation plays are quickly becoming the answer to the question what’s next after the Eagle Ford and the Bakken peak,” he said.

There is more opportunity for dual laterals and in thicker intervals in Mississippian Lime, in particular, Castell said.

PetroQuest has not drilled many stacked laterals, and Mitchell said the one dual lateral Newfield has drilled in the Arkoma Woodford was fairly cost prohibitive. “But it does not mean that’s not something we should look at in the future in terms of full-scale development,” she added.