Achieving Custom Bakken Frack Solutions

After a year in the lab, Nine Energy proved a nontraditional method can increase stage count, frack control and Bakken well production.
By Luke Geiver | May 05, 2016

Kendall Manning is happy to debate the various ways an unconventional oil well should be hydraulically fractured. As an oil industry veteran, Manning has been involved with numerous projects and well-completion strategies from Texas to North Dakota. He’s seen firsthand which approaches yield the most desired results in his 20-plus year career working for the likes of Halliburton, Baker Hughes and others. As the Director of Sales for Nine Energy, an energy services company with more than 500 employees and operations in every major U.S. basin, Manning was involved in a unique hydraulic fracturing method that has reduced the number of days needed to complete a 50-stage Bakken well from 15 days to two.

We spoke with Manning about the research and results from Nine Energy’s new Divert-A-Frac system ahead of the soon-to-be-published Society for Petroleum Engineers paper detailing the multi-party effort.

Developing The Divert-A-Frac
According to Ricky Green, vice president for Nine’s Rocky Mountain region, a nondisclosed operator was looking for a single-point entry solution to increase stage count on a 10,000-foot lateral in a Bakken-targeted well. The goal was to increase frack stage count from 35 stages to 50 without using limited entry cluster stimulation. Manning, who remembers when Bakken operators were fracking wells with only eight stages per well, says the effort and research required to make the leap from 35 to 50 stages was no easy task. “We had gotten to where our basic stuff in the Bakken was either a 30 or 35 stage system,” Manning says. “This [35 to 50] is a substantial jump.”

Over a period of one year, Nine Energy’s team researched, tested and designed a system to meet its client’s needs. The final system utilizes swell packers to isolate each desired zone spaced at roughly 250 feet. Each discrete fracture zone includes frack sleeves pressure tested with dissolvable metallic actuation balls. Computational fluid dynamic modeling was used to demonstrate and verify that ball-on-seat performance would not be affected by the planned proppant stimulation in the 50-sleeve system. “You can simulate millions of pounds of proppant going through that seat,” he says of the computational modeling. “The tolerances are so tight we have to make sure we aren’t going to erode the seat.”

Because the balls can only range in size from 3 inches to roughly 1.5 inches, the tolerances for the individual balls and sleeves are very tight, he says, and there is no room for error if the desired results of 50 isolated frack sections are to be achieved. The computational modeling showed the system would work, but in-field testing also provided assurance the tight tolerance of the ball-seat sleeve system would hold up to immense pressure and proppant flow. During the first live test, Nine’s team followed pressure signatures created during a frack job using the DAF system. “You could see a pressure signature every time a ball was seated,” Manning says, proving that once dropped, the balls were holding and the isolated portions of the well were receiving the appropriate stimulation load.

DAF In The Bakken
During its use in the Williston Basin, the Nine team fracked a 50-stage well in roughly 50 hours. In comparison, a 50-stage cemented plug-and-perf system can take over two weeks, Manning says. The well was stimulated with 3.5 million pounds of proppant and roughly 2.1 million gallons of fluid. During the frack job, each stage took roughly one hour and there was zero non-productive time related to the DAF system.

The system is designed for high volumes of proppant and fluid. And, according to the Nine team, it works best on long horizontal wells in the 10,000-foot lateral length range. Currently, Manning believes individual frack stages will be spaced at 250 feet because “you aren’t going to get much more increased drainage by fracking every 100 feet versus fracking every 200 feet.”

Until the SPE paper is published, Manning is not at liberty to discuss the productivity gains achieved by the stimulation approach, but the initial client that asked for the custom solution is now deploying the method in all new wells. The operator is also looking to add friction reducers to the fluid to increase the amount of pressure applied to the rock. In North Dakota, surface restrictions on pressure pumping applications limits the amount of pressure that can be applied downhole. “The more hydraulic force you apply, the more exposure that you get, which means more production,” Manning adds.

While Manning is working to expand the use of the system to other plays that feature longer laterals, the team is already back in the lab working on a new custom solution for its existing Bakken clients. “Everybody thinks we just use a bigger hammer but there is a lot of science involved in all of it,” Manning says. So, only a few months after proving the DAF solution, the Nine team is working on its new request. “The operator wants to know how we can do more than 50.”