Weatherford, Baker Hughes refine fracking tech
A more 'intelligent' technique evolves as resource plays expand
Weatherford International Ltd. has a history that dates back 70 years, but it’s the application of a relatively new technology that’s driving the service company’s North American business – hydraulic fracturing. “In the last five years it came from absolutely nothing to emerging as our second-most prominent technology” behind drilling, says Clayton Andersen, global product line technologist with the Geneva, Switzerland-based outfit.
His company isn’t alone. Somewhere between 70 and 80 per cent of frack jobs in the world are performed in North America, providing producers with access to oil trapped in hard rock formations, shale in particular. In its World Oil Outlook 2011, the Organization of Petroleum Exporting Countries estimates production from shale reserves will help drive global production of unconventional oil from 2.3 million barrels per day in 2011 to 8.4 million barrels per day in 2035. Canada and the U.S. could supply 6.6 million barrels per day, the cartel predicts.
Bullish forecasts mask a subtle shift. Fracking is not cheap. But while the upfront costs are steep – “in the neighborhood of five times what a conventional completion might be,” Andersen says – service heavyweights like Weatherford, Baker Hughes and Schlumberger are quietly refining an earth-shattering extraction technique that has rewritten the global energy playbook.
If the past five years could be summed up in a word, it would be more. The ascent of unconventional drilling techniques has been defined by more horsepower, more fluid, more proppant, more days spent on a well site, more expensive equipment and labor. But with those higher costs, Andersen says, comes higher production; somewhere in the range of 25 times higher than a conventional completion, he estimates.
After five years in the field, though, operators are looking for more than just improved production. Increasingly, they want to streamline operations and better integrate drilling, completions and production, suggests Doug Pipchuk. “We’re at the point where we’re going from a brute force technique to a more intelligent pinpoint technique,” the technical manager for Schlumberger Pressure Pumping Services in Canada says.
Consider packers, for instance. It used to be that one packer – a sleeve inserted down the well to isolate a portion of the reservoir for a frack job – was enough to complete a well. “Now, it isn’t just one packer; it’s 20 packers and all 20 packers have to work,” says Darryl Firmaniuk, engineering manager of completions systems with Baker Hughes Inc. in Calgary.
The extra equipment and time added to a completions job has made co-ordinating drilling and production programs a matter of course. If there is a blip anywhere along the line, whether it’s during fracking or another part of the drilling process, the whole operation comes to a standstill, Firmaniuk says. Meanwhile, crews still need to be paid while repair work is done.
“Getting all of the disciplines involved in a frack to work together and have the schedule be as timely as possible is very important,” he says. “Especially with multi-stage fracturing, because there are so many disciplines involved in the process – not even just on location, but even from headquarters in Calgary. You have to have a certain amount of communication and co-ordination there as well. If anybody is out of sync it affects the entire process and that’s why you always have to be on top of your game.”
Completing a well in multiple stages helps streamline completions, industry participants say. There are multi-stage frack systems available that have increased the number of stages from 20 to 40. In either case, incrementally sized plastic or metal balls drop down the well to isolate sections of the horizontal wellbore, so multiple frack jobs can be targeted into a reservoir.
Following the completion, those frack balls need to flow back to the surface for the well to start producing. As horizontal wells got longer, officials at Baker Hughes noticed that not every reservoir has enough pressure to push the balls out of the wellbore. Sand or other debris can also build up in the liner, blocking the ball’s path to the surface.
Operators could just accept the lost production or stop operations while a coiled tubing unit is brought in to remove the balls. But at a cost of $150,000 between hiring equipment and lost time, it’s not a cheap fix. Equipment shortages can exacerbate a delay. “If you don’t have a coiled tubing unit scheduled, it can be tough to get one,” Firmaniuk says.
Cue disintegrating frack balls. Using proprietary material Baker Hughes developed 15 years ago, the company created what it’s calling IN-Tallic frack balls. The disintegrating frack ball looks and feels like an aluminum ball, but its composition chemically reacts with brine fluids to disintegrate over time. “There are a lot of other balls out there that are biodegradable, but this is a chemical-degradable ball,” Firmaniuk says. The balls don’t disintegrate immediately like an Alka-Seltzer tablet. It’s a slower reaction that can take up to two months.
Baker Hughes first deployed the technology in North Dakota’s Bakken formation about a year and a half ago. Firmaniuk says the company is working with just one major producer in Alberta. He doesn’t think it will be too long before the technology is widely adopted in Western Canada. “For Canada, we’re just at the cusp of these balls starting to be asked about more often than not,” he says.
Sand and debris accumulating in the wellbore aren’t just a hazard for frack balls during a well completion. Clogging up the path can stop fracturing fluid from reaching its target or else stop the resource from reaching the wellhead. Sand or other fine particles are a necessary part of frack fluid. After the high pressure fluid fractures the underground rock, proppants keep the cracks open so the oil or natural gas can flow into the production well.
Schlumberger Ltd. has found a way to reduce the amount of proppant without negatively impacting production. The Houston-based company’s HiWay channeling fracture technique uses half the amount of proppant as a typical frack job by pulsing fluid without proppant in with the regular mix of fluid and proppant.
The pulses are separated by a proprietary mixture of fibers and gels. They last only seconds, but create open channels for fluid to flow through, rather than flowing around the proppant. Having the pulses hold open fractured rock, rather than proppant, reduces the chance of a screen-out – where sand blocks fluid flow – and eliminates the need for a coiled tubing unit, the company says.
Screen-outs used to occur once every fifth or sixth well, Schlumberger’s Pipchuk says. “Now when you have 20 stages in a well it might happen every well,” he says. “We’ve actually seen a reduction in the industry-wide screen-out rate from about five per cent to less than 0.1 per cent.”
Schlumberger’s channel fracturing technique has been commercial for two years. The company has done about 200 treatments in Canada and more than 5,000 around the world. If you measure the technology’s growth by the number of jobs it has created inside Schlumberger, the channeling fracture technique is the fastest growing technology in the company’s history, according to Pipchuk.
It not only reduces downtime on a well site; it boosts production rates, Pipchuk says, because channel fracturing creates a better conductivity path to the reservoir. “In Argentina, on some of the first wells we’ve done, these increased rates are holding up for over two years now,” he says. “Everything in between is bearing that up as well.”
Including pulsed stages of clear fluid with no proppant requires a specialized blender on the well site. The company says that overall, since its technology reduces the amount of proppant and fluid by up to 50 per cent, the equipment footprint on the surface can also be reduced in some situations. “If you take the Eagle Ford [shale play], for example, where we’ve switched from doing slick-water fracks to doing HiWay fracks, our surface footprint has actually decreased because we’re able to pump at a lesser rate, so you need less horsepower on location,” Pipchuk says.
The advent of real-time information while fracking and improved computer modelling of geological formations will refine the process further, the completions boss says. “The major advancements are going to be maximizing the effective reservoir contact while reducing the amount of resources and footprint required,” he says. “The way to do that is not necessarily to go with brute force, but to fracture smarter, do it with intelligence.”
More posts by Steve MacLeod
- Rethinking the Role of the National Energy Board
- Does corporate social responsibility pay?
- Opportunities arise for new midstream companies like Kanata Energy Group
- Can Alterra Power Corp. convince investors to buy into renewable energy?
- Cash is king over debt and equity financing in energy deals