“There’s a huge upside in driving efficiencies in our industry,” said Dan Themig, president and CEO, Packers Plus Energy Services. Themig spoke at Hart Energy’s DUG Permian Conference and Exhibition on the topic of how to improve well results in a low-cost environment.
“One thing I think we sometimes overlook is effectiveness of our existing completion practices,” he said. A recent study found, for instance, that more than one-third of stimulated stages in unconventional reservoirs did not contribute to production. Poor cluster efficiency also leaves reserves behind, said Themig. The problem occurs because reservoirs are not homogeneous, and differences in properties along the length of a lateral influence where fractures initiate and grow.
Replacing stages with complexity is a potential solution to this issue, making completions better for less cost. A technique that has promise in this emerging area is rapid execution strategy. This approach hinges on generating fracture complexity and actually affecting the rock mechanics of the reservoir.
One firm, Painted Pony Petroleum Ltd., has dramatically improved its type curve from 5 Bcf to 13.5 Bcf per well in Canada’s Montney play, partly by using the rapid execution strategy. The company first drills parallel well pairs. It rapidly fractures all the stages in the left-hand lateral, and the well is left shut in with no flowback. Then, the completion crew quickly moves to stimulate the right-hand lateral.
The goal is to get the fracks to collide with each other and create a sizeable area of complex fractures between a well pair. The concept can work in both openhole and cased laterals, but observations to date on both types of completions have shown that openhole completions respond particularly well, exhibiting a high number of early-time and lower-intensity fractures, noted Themig.
Ensuring flawless execution on location is another area of focus for operators. Packers Plus has unveiled its new e-PLUS Retina ™ monitoring system, which collects and analyses real-time data using a device that is small and easy to set up. This device supplies immediate feedback about the job as it is occurring, including detecting such incidents as a ball that fails to launch or a double shift on a stage. The quick feedback allows field operators to swiftly make adjustments on site and make sure each stage is properly treated.
“We have driven our efficiencies up close to 100% on the jobs that we have been on,” said Themig. “I believe that we will be able to determine—in real time, on the fly—when we are getting complex fracture development.”
A third evolving strategy that has promise is the drilling of dual and triple-lateral wells. This tactic would work well in the Permian Basin, given its multiple horizontal targets, said Themig. “It is possible to design wellbore construction to do downspace drilling from existing wellbores, and this can include dual laterals.” Currently, operators use single-well pad developments for all the objectives in an area; now firms are seriously looking at drilling infield and multi-layer wells from a single wellbore.
The potential cost benefit of multiple laterals is clear; the issues have been with execution. But that is changing: Themig’s firm has now been involved in completing more than 1,000 laterals in dual and triple-lateral wells. In these projects, a frack string with a bent joint is run into the well. This allows access to the selected lateral. After the first lateral is stimulated, a bridge plug is set above the open hole to prevent balls from transferring over into the second leg.
While each of these technologies is still being tested and developed, they collectively offer the possibility to deliver the oilfield Holy Grail to completion engineers—better, cheaper wells. “Driving costs down is only part of it; our goal is to move those cumulative curves up as well,” said Themig.
The most successful companies will be able to do both.