When it comes to hydraulic fracturing, steadiness may not be a virtue. That was the conclusion of a test to see if rapid pump rate variations would lead to greater production than conventionally fractured stages when the pressure was held steady.
The stages in which rapid pump variations were used to create pressure pulses produced an average of 18% more gas than the ones with steady pumping pressure, said Jordan Ciezobka, manager of research and development for the Gas Technology Institute (GTI), which did the test in the Marcellus with WPX Energy. The project was funded by the Research Partnership to Secure Energy for America (RPSEA).
Based on early results, this simple method may “increase production with no change in the water or sand pumped,” he said during a presentation at the recent SPE Hydraulic Fracturing Technology Conference.
Since then, a version of the method with “more aggressive rate changes engineered specifically to accommodate the completion design in the Permian Basin” has been tested at a site where it was monitored using microseismic, production logging, and radioactive tracers. Ciezobka said results from that test are expected soon.
The idea grew out of previous well monitoring research work in which microseismic testing detected a surge in seismic activity—an indication of more fracturing—whenever the pump speed had to be adjusted for operational reasons.
Where that happened during fracturing, the well’s output was greater, Ciezobka said. So the thinking was, “Why not redesign the frac pump rate to get higher microseismic activity and get more production?,” he said.
To test the theory, GTI set up a test where it used a variable pumping rate on 14 odd-numbered stages, and a steady rate on 13 even ones. The pump rate variations were done during the pad period, prior to pumping proppant. In a future test they plan to also vary the pressure while pumping proppant.
Other than the rapid pump rate changes, which required some practice by the crew to get it right, the odd- and even-numbered stages showed no differences.
But on average, the stages where the pumping rate varied produced 65.4 Mscf/D of gas, compared with 55.5 Mscf/D when the rate was constant, the paper said. The six highest production rates resulted from stages in which the pressure was varied.
When production from the test well was compared to a nearby well that had been conventionally fractured with 50% more proppant, the variable rate well’s production had declined at a lesser rate.
Another difference was surface treating pressure, which is an indication of the force required to pump fluid into the formation, which was lower when the pump pressure was varied. Analysis of the pressure decline rate after the pumps were shut down (water hammer diagnostic) indicated variable rate stages created, broader, more complex fractures, he said.
