FORT WORTH, Texas—Better completion techniques, tighter lateral spacing and greater proppant loading have helped propel fields in the Permian Basin above their unconventional peers in other parts of North America.

Sand, spacing and slickwater have all played key roles in the multistage fracturing process that has changed the world’s energy landscape. Of the major unconventional basins in the United States, the Permian leads production. According to the U.S. Energy Information Administration’s latest drilling productivity report, more than 2 million barrels per day (MMbbl/d) of oil are produced in the Permian—about twice as much as the nation’s next biggest oil producing regions.

Future growth is anticipated as operators and oilfield services companies learn more about geology of specific areas and fine-tune techniques with goals of safely unlocking economic hydrocarbon molecules from the ground.

A panel gathered to discuss technology and techniques May 25 at Hart Energy’s DUG Permian conference. Speakers on the panel included Mark Hiduke, CEO of PCORE Exploration & Production II LLC; Jim Wicklund, managing director of equity research for Credit Suisse; Ole Engels, vice president of reservoir development services for Baker Hughes; and Tobias Judd, reservoir engineering business manager, North America, Schlumberger.

Here are their thoughts, which have been edited for length and clarity, on hot topics such as drilled but uncompleted wells, completion techniques, IP rates and economics, among other areas.

How quickly can drilled but uncompleted wells be brought online?

Wicklund: Most of the guys in pressure pumping who had been working 24/7 are now working five days a week. By hiring some additional people and using no real additional equipment, they could double capacity with equipment they currently have. Most of the increase in activity will occur in the Permian. I’m not so sure that many people laid off in the last 12 months in Midland have either found work outside the oil business or have moved elsewhere. It may not be quite as hard to get people as some think. We did a survey of pressure pumping companies and asked them how long it would take to hire people, train them and put them to work, the consensus was between four and five weeks.

How do you get best-in-class or better-than-average completions in the Permian?

Hiduke: Building on team members’ experience and knowledge as well as learning from others in the business. We look at where we are in the basin and use data on areas such as on pounds per foot on completions and how certain types of sand affect the well and other variables. We basically take our knowledge and the knowledge that we get from around us and we high-grade. We determine what we think will work best in this area. We were in northwest Reagan County and decided to switch to white sand at that depth. We used more 30/50, a bigger prop size, and used a bit of gel because of the prop size. But you want to stick with slickwater as much as possible to keep costs down. If you’re using only 100 mesh or 40/70, I think you can use slickwater all day long.

Is slickwater, plug and perf, tighter spacing of about 200-250 feet and greater proppant loading—all common in most basins—the magic recipe or just a reaction to today’s low-price environment?

Judd: The industry has done a good job at evolving and generating the best value possible from each play. Does this mean we’ve found the recipe for all future wells? I don’t think so because as we move to different parts of the reservoir, different parts of the basin, reservoir quality is changing. I still believe there will be a strong reliance on modeling and understanding performance. It just can’t necessarily be a cut-and-paste approach on all wells.

Are economics driving the industry mostly to slickwater?

Engels: A lot of economics is driving this. Even in a slickwater, sand environment, EURs are increasing. Big wells are coming online. Technology drives larger EURs, but you have to watch the economics per barrel. The industry has done a fantastic job with increasing frack intensity, pressure, volumes and understanding the resource. Is there a step change? Are there technologies emerging today? We see a lot of hope with frack engineering.

What’s best approach to Permian Basin acreage?

Hiduke: Nothing that we do is too shocking. It’s taking the best approach from others and seeing what else can be done. Longer laterals are better in the Midland Basin. Geosteering wells to land in the most brittle rock is huge. Now we concentrate all frack designs around the wellbore. The intensity is around the wellbore. You want to drain what’s around the reservoir. What we’re seeing—even for offset wells—is when you put away more pounds per foot, a larger grain size, associated fluid rates that goes with increased pounds per foot, you end up with not only a higher IP but a sustained rate.

Is the pattern or order in which adjacent laterals are completed a local phenomenon or a trend?

Engels: I don’t think it’s local. Strategy here becomes really important. Models have become so sophisticated. We can model reservoir drainage with 3-D coupled with economic models, for five- to 15-year payout. It may not be something you read about in the paper, but if you want to have a solid strategy you look at these things. There is much more scientific base than there was 10 years ago.

Are rising IPs a sign of high-grading or is it proof that operators are getting better?

Wicklund: We are getting better, from drilling efficiencies, with room for improvement in the Permian, to the effectiveness of fracks. But is the last incremental barrel economic? That’s driving more efficiencies, focus on returns and technology development. You always accelerate technology development during wartime, and I would argue that the last six quarters have clearly been wartime. High-grading has mattered, but the scary part is the amount of inventory that is present. The Permian has four times the inventory of any other basin. Production per well continues to increase. The problem comes when you combine rig efficiency with completion efficiency and the higher production per well. It impacts how many additional rigs it takes to meet future demand. We may never get back to rig count levels we saw 15 months ago in our immediate lifetime—a positive for operators, but not always so for service companies.

Velda Addison can be reached at vaddison@hartenergy.com.