As another year begins for oil and gas development in the Williston Basin, operators continue efforts to optimize operations in order to maximize production efficiencies. Among those operators is Norwegian state-owned Statoil Oil and Gas which has been experimenting with slickwater fracks and comparing results to its traditional method of using gelled fluid fracks.
Lance Langford, Statoil’s vice president for Bakken operations, spoke with Petroleum News Bakken in early January about the fundamental differences between the two methods, the approach that Statoil is taking in its experiments, and the results of the experiments, which are generally positive but are very much area-dependent.
Traditionally, Statoil, which entered the Williston Basin in 2011 through its acquisition of Brigham Oil and Gas, has employed gelled fluids with ceramic proppant in plug-and-perf fracks where the proppant is suspended in the frack fluid. In a slickwater frack there are no gels. The proppant is not suspended in the fluid and tends to settle in the bottom of the frack wing. Langford says the proppant in a slickwater frack actually forms dunes along the bottom of the frack wing.
Slickwater fracks result in longer lateral frack wings but have less vertically propped frack wings, according to Langford, because the proppant is not suspended in the fluid and has less tendency to migrate upward and prop open the upper portions of the frack wings that form under frack pressure. On the other hand, Langford said, gelled fracks have shorter lateral lengths but more complex fractures near the wellbore and result in more vertically propped frack wings, including upper portions of the frack wings.
Fracturing and propping upward into the upper Bakken is particularly important, Langford said, because he believes propped fractures that extend into the upper part of the middle Bakken and even beyond into the upper Bakken shale can add significant reserves and value.
Consequently, Langford believes “with Slickwater fracks you get the longer skinnier propped frack wings, but you don’t get the upper portions of the frack wings propped compared to gelled fracks. The gels will suspend the proppant and you’ll get propped fractures above the middle Bakken into the upper Bakken, whereas in a slickwater frack, proppant will fall to the bottom of the frack wing and create dunes.”
Acquiring and evaluating data
Statoil’s gel fracks have worked well across all of its Bakken acreages, Langford said, so the approach to testing slickwater was to look at rock properties and formation thicknesses and identify areas where slickwater fracks looked to have potential. Statoil then drills and completes slickwater wells side-by-side with offset gel-completed wells and compares production data in an apples-to-apples comparison.
There are, however, two primary problems with evaluating such data. First is the question of how long a well should produce in order to provide enough data to assess performance. That, Langford said, is the hard part. Six months, he said, are better than three, and nine months are better than six, but he added that it is essentially a matter of how confident one is in making decisions based on a certain set of data. “It’s about a confidence level. The longer you have production, the more confidence you have in your decision.” Personally, Langford said, he likes to have at least 12 months of data before making decisions about going to full-field development.
The second question is whether the positive slickwater results from one or a few wells are enough to justify applying slickwater versus gel fracks over a larger area of development. Because of the longer frack lengths, Langford said fewer wells may be needed to develop a given spacing unit, and if too many slickwater wells are drilled, the chance of well communication increases. When the broader economics are considered, the matter gets more complicated. “Is it three-well spacing or is four-well spacing required on slickwater, and what does that look like on the economics compared to a four-well gel frack job?”
Extrapolation of data over a full area of development is ultimately the key for Statoil in its decision-making process. And while Langford is optimistic about slickwater fracks, he is also cautious.
“I think we’ve got a good chance that that technique’s going to work in some areas but we just have to look — before we make a mass change — look and see what a full unit development looks like, what do the economics look like, what the recovery factors look like?”
Statoil has been conducting its slickwater experiments over the last 12 to 18 months, and Langford expects that within the next year he’ll have a better idea as to where and how well slickwater will work for the company’s Williston Basin operations.
Organizing data
On a related matter, because the frack methods perform differently in different areas, Langford said Statoil breaks performance data into a variety of subgroups within different counties. That allows Statoil to make direct, apples-to-apples comparisons, not only with its own data but with data from other operators. That process, Langford said, is essential, and noted that farther west into eastern Montana the quality of the basin deteriorates. “So you’ve got to break that down into multiple areas as you move west,” he said. “But you know, your hope is to continue to figure out ways in completion techniques that make those areas economic or more economic.”
Optimum frack stages
Statoil has been experimenting not only with slickwater, but also more generally with various numbers of frack stages.
Langford said Statoil has found that 30 to 32 stages using the plug-and-perf method are optimal and that any number beyond that range is not adding much value to the economic performance of a well. “We early-on drove those frack stages way up beyond where anybody ever dreamt and people used to say we were doing too many. And really we ultimately did, but that’s what we were trying to find,” he said, adding that “We think 40 stages using plug-and-perf is too many — 30 to 32 stages is what you should be planning.”
Increasing proppant
Statoil has also been experimenting with increased proppant loads, which Langford said has resulted in increased estimated ultimate recoveries, EURs, because of greater complexity in the fractures near the well bore but not much more frack length as seen by microseismic data. Traditionally Statoil has used nearly exclusively ceramic proppant, except for some 40/70 white sand that it has used as a fluid-loss additive, and a scouring additive, but Langford added that “it doesn’t add to the conductivity and the productivity of the well.”
Statoil philosophy
Statoil’s meticulous and systematic approach to frack experimentation is nothing new for the company. “It’s the same approach we’ve had since day one,” Langford said. “We don’t want to change too many variables and we don’t want to jump out and change what we’re doing that we know works too quickly because you make mistakes.”
And Langford said keeping an open mind is equally as important. “I think our job is to always be open and look for techniques that are better. And right now in certain areas I think slickwater is very promising.”
