Running a shale exploration and production operation requires a sharp focus on costs, but not all are measured the same. BHP Billiton’s method for evaluating the cost of drilling an unconventional well is different from the one used to gauge the cost of completing one.
The difference reflects the potential production upside of spending more to fracture formations more effectively compared with drilling. BHP is seeking ways to create more productive fracture networks by manipulating the stresses in the rock between wells, and seeking efficient ways to go back into older wells without the cost of the hardware needed for the initial fracturing work.
“Productivity improvement is something we are relentless about at the moment,” said Rod Skaufel, president of North American shale at BHP, during a recent company briefing in Houston.
He said the Australian mining and energy company realized about a year after acquiring onshore assets in the US that the management methods used for offshore development were not going to work when mass producing wells onshore. There was a wide gap between its cost to drill a well and what competitors were paying for comparable work. Over the past six quarters, it has recorded a 26% increase in drilling efficiency, said Skaufel, adding that BHP is “one of the fastest drillers in the Eagle Ford.”
When it comes to completing shale wells, the productivity measure shifts from a comparison of the cost-per-foot to drill to calculating the return on investment based on long-term production. BHP’s challenge is maximizing the return on USD 4 billion annual budget for US shale operations, which is not expected to change much this decade, and a staff that has grown to 2,000. Those resources must be allocated over four plays that could absorb more money and staff time than the company has available.
For now, BHP’s development focus is the Eagle Ford Shale, with 17 of its 25 rigs drilling in the South Texas play. The rest of the rigs is split between the Permian Basin and the Haynesville plays in Texas, where it is doing detailed studies to improve its results when it increases activity in the future. BHP is also in the Fayetteville Shale.
When completing wells, BHP is looking for ways to modify how it uses the current tools to deliver more sand to prop open fractures, and is testing new options. The company concluded that it could increase the output of its wells by 20% to 60% by delivering more proppant in fractures to hold them open, Skaufel said. To do so, it is using more viscous fluid mixes able to transport more sand and larger percentages of finer sand (100 mesh), which is less likely to settle out during fracturing and can fit into smaller fissures.
Planning and research efforts are considering how to space wells to maximize their output over the 2-year time frame it uses to evaluate wells. One pilot is testing a three-well pattern designed to encourage more complex fracture networks, which could mean a greater output using an idea from the University of Texas at Austin.
The goal is to change the natural stress patterns in the rock among three parallel wells so that when a hydraulic force is applied, the cracks created form complex patterns. Two horizontal wells on the outer edge are fractured, creating stress shadows that are expected to cause more complex, productive fractures when the third well is fractured.
“We fracture from the outside in to create in-situ stress,” Skaufel said. It requires spacing the wells close enough to allow overlapping stress and limiting the fracture length to avoid overlapping fractures. The measure of success will be long-term production. While there is a lot of attention paid to initial production rates during the first 100 days of output, he said that longer-term production studies show that the wells with the highest early output tend to trail after 2 years.
The company is also looking for a method to cost-effectively refracture older wells. BHP is partnering with Schlumberger to work on ways to use its BroadBand chemical treatment to allow the operator to target specific spots in a well without having to physically isolate those areas using bridge plugs.
BHP is taking its time in the Permian Basin where the exploration challenge is picking which of the many options will offer it the best return. Although its Black Hawk play in the Eagle Ford appears to offer the most productive rock, the Permian offers many more options. Beneath leases covering 450,000 acres, there are three horizons, each containing another three potential zones, to develop, he said.
In the Haynesville Shale, four rigs are working as BHP seeks the best development option. While gas prices have risen to nearly USD 5 per Mcf, its formula for choosing which wells to develop based on future price trends favors liquids-rich basins over gas producers by a wide margin. For now, the company is looking for the most effective way to space wells and complete them in the Haynesville, preparing for the day when full-scale development resumes. “Gas is not going anywhere we have time,” Skaufel said.
