Running a shale exploration and production operation requires a sharp focus on costs, but not all costs are measured the same. BHP Billiton’s method for evaluating the cost of drilling an unconventional well is different than 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 to drilling. BHP is seeking ways to create more productive fracture networks by manipulating the stresses in the rock between wells, and by 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, asset president for shale at BHP Billiton Petroleum, during a recent briefing in Houston covering its US shale operation.
Skaufel 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 in drilling efficiency, said Skaufel, adding that BHP is “one of the fastest drillers in the Eagle Ford (formation).”
When it comes to completing those wells, the productivity measure shifts from a comparison of the cost-per-foot, to calculating the return on investment based on long-term production. BHP’s challenge is maximizing the return on the USD 4 billion annual exploration and production budget, which is not expected to change much this decade, and a staff that has grown to 2,000. Those limited resources must be allocated over four plays that could absorb more money and staff time than BHP has available.
For now BHP’s development focus is in the Eagle Ford, where 17 of its 25 rigs are running, with limited drilling in the Permian Basin and the Haynesville plays, where it is doing detailed studies to improve its results when it ramps up in the future. It is also in the Fayetteville shale.
When completing wells, the company said it looks for opportunities to modify the ways it uses current tools to deliver more sand to prop open fractures, and is testing new options. BHP concluded 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 that are able to transport more sand and larger percentages of finer sand (100 mesh), which is less likely to settle out during fracture and can fit into smaller fissures.
Planning and research efforts are considering how to space wells to maximize their output over the two-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 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 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 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 totals over two years often show the high early rates are accompanied by early declines.
The company is also looking for a method to cost-effectively refracture older wells. BHP is partnering with Schlumberger to develop 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. This approach could offer a cost-effective option where the hardware is lacking.
BHP is taking its time in the Permian Basin, where the exploration challenge is picking which of many options will offer it the best return. While BHP’s Black Hawk play in the Eagle Ford appears to offer the most productive rock, the Permian offers so many options. Beneath leases covering 450,000 acres, there are three horizons, each containing anther three potential zones to develop, Skaufel said.
In Haynesville, there are four rigs working as BHP seeks the best development option. While gas prices have risen to near USD 5 per mcf, its formula for choosing which wells to develop based on future price trends favors liquid-rich basins over gas producers by a wide margin. For now, the company is looking 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.
Stephen Rassenfoss is the Emerging Technology Senior Editor for the Journal of Petroleum Technology.