Several US shale drillers are focusing on mature fields, vertical wells and refracking in an effort to sustain cash flow as the downturn continues, write Anna Kachkova and Andrew Dykes
US producers that have until recently been focusing on horizontal drilling are increasingly turning back to vertical wells, mature fields and refracturing as ways of sustaining cash flow as oil prices remain low.
Reuters reported last month that while initially the availability of funds, super-sized frack jobs and steep discounts on oilfield services and equipment had helped to sustain production as prices fell, now producers were shifting their focus from output growth to capital discipline.
“It makes more sense to develop vertical wells in a lower price environment because they are not growth plays but they are a very strong cash flow asset,” a Wood Mackenzie principal analyst, Benjamin Shattuck, told the news agency. “They are going to give you that cash flow that you need today.”
According to Baker Hughes figures, the US vertical rig count has risen by around 20% in recent months, from 99 in early June to 110 rigs in the week of October 23. The horizontal rig count meanwhile, has dropped from 673 to 591. With tens of thousands of older onshore wells in existence in the US, the fresh focus on them is already resulting in new output.
Companies shifting their focus to mature fields and vertical wells include Devon Energy, Noble Energy and Apache, among others. In meetings with investors earlier in September, all three companies devoted more attention to mature oilfields and vertical wells than they had done previously.
Devon has been one of the leaders in terms of refracking older wells – particularly vertical wells – in North Texas, as the process is cheaper than drilling and fracking new horizontal wells.
“Even in a mature area like this, there’s upside our technical teams are looking at,” DevonDevon’s CEO, Dave HagerEvonD told investors in September.
Devon said it had refracked 150 vertical wells and was testing the technology on older horizontal ones, where the process is less predictable.
Noble said it anticipated producing more than previously expected during this quarter, with its performance boosted in part by vertical wells at the company’s Denver-Julesburg Basin acreage in Colorado. Noble has raised its anticipated third-quarter sales volume range to 360,000-370,000 barrels of oil equivalent per day, representing a 10,000 boepd increase on the midpoint of its prior estimate.
“Production from our legacy vertical wells and older horizontal wells [is] benefiting from substantially reduced line pressures and improved third-party plant uptime,” said Noble’s executive vice president of operations, Gary Willingham, in a statement.
Apache, meanwhile, is focusing on its legacy oilfields in the Permian Basin, where it has both horizontal and vertical wells.
“We’ve got a lot of low-hanging fruit in terms of little quick projects you can do and get your money back in six or seven weeks and add significant barrels,” Apache’s CEO, John Christmann, told the Barclays CEO Energy-Power Conference.
Christmann went on to say that the company would invest more in the region – which accounts for 27% of Apache’s output, or around 77,000 boepd so far this year – if prices remained low.
Vertical wells and mature fields are currently looking attractive to drillers because they allow them to produce more at a lower cost. They generally require less powerful rigs that are cheaper to rent, and take less time to drill.
Reuters noted that whereas a large horizontal well could take a month or longer to drill, a shorter vertical well might take as little as 10 days to be brought on line.
While shale drillers have recently brought about considerable reductions in the cost of drilling, company data indicate that a horizontal well of around 10,000 feet (3,000 metres) can cost around US$5-9 million to drill even with the discounts currently available. Meanwhile, a vertical well can be drilled or refracked for around US$1 million.
Refracking is proving attractive for similar reasons. Earlier this year, it was reported that refracking a well costs around US$2 million. While results from refracking have been variable thus far, the increased use of the technique in recent months is already leading to improved performances. Indeed, in Devon’s Q2 earnings presentation, it reported that “[vertical] refrac costs have declined to as low as US$270,000 per well.”
This could be expanded into horizontal refracks. The company added that during H2 2015, it would “continue to evaluate the commerciality of this opportunity by testing refracs on up to 15 horizontal wells.” Its latest update, due in the next few weeks, should provide a decent indication of whether or not it has been successful.
Halliburton also looks to be making good on the US$500 million it received from Blackrock in July to help enable its ACTIVATE Refracturing Service. The scheme incorporates a number of disciplines, including a stimulation service, coiled tubing, the FracInsight Service, Pressure Sink Mitigation and other expertise. The result, it says, is that refracks are “more reliable and predictable.”
Indeed, Halliburton president Jeffrey Miller told reporters on a call following the company’s Q2 earnings results that the company saw “a significant runway for refrac in the future.”
If you believe the figures, he appears to be right. The firm reported that the service was seeing up to an 80% increase in estimated ultimate recoveries (EURs) per well, up to a 25% increase in oil recovery factor and a reduction in cost per boe of up to 66% compared to new drilling. In the oil window of the Eagle Ford, Halliburton’s technology was reported to have raised the average EUR of wells by 121%.
In line with producers, Halliburton is so far focusing on the lowest hanging-fruit and lowest-cost wells before moving onto more wells that require more sophisticated work. It also noted that while not every well would see such dramatic improvements, Halliburton had not had a single well negatively affected by a refrack.
Meanwhile, in August Schlumberger reported that it had eight refracking clients in North America. This figure too is likely to grow, evidenced by the fact that at the end of September the firm signed a licensing deal with the UK’s Highland Natural Resources for Diversion Technologies’ DT Ultravert, a system with potential in the refrack market.
The deal is a coup for Highland, which only acquired a 75% interest in Diversion’s patent applications in May this year.
According to Schlumberger, while current diversion technologies operate near the well bore, DT Ultravert penetrates into the reservoir and diverts where oil and gas have already been produced. “The DT Ultravert process injects gas into the depleted area of the reservoir and re-pressurises the area, forcing the refracture fluid to divert to under-depleted areas,” it adds.
The process also uses non-damaging gases – most likely nitrogen – which flow easily back to the surface once the well is in production.
With potential for “easy deployment anywhere in the world,” the technology is evidently exciting enough for Schlumberger to snap it up.
The acquisition adds to Schlumberger’s stable, which already includes the company’s touted Broadband Sequence service, a system which claims to have increased the productivity index of a refractured shale well by 600%.
In a recent interview with Canada’s Oilweek, the company’s technology integration manager, Andrew Acock, commented: “We’ve brought some very low producers back to 70-80% of their original production rates with pressures coming back up to the original levels… [Successful refracked wells] have enough production to pay the refracture costs under one year and increase the returns.”
While noting that “It’s still early in the game,” Acock concluded that the firm was “taking a relatively simple approach, but it does seem to be economic if you do the proper candidate selection. We are excited about the opportunities for refracturing.”
While there has been scepticism over the potential of the refracking market, given the ongoing unpredictability of results, new testing is helping drillers to hone their techniques. Now with services firms making technology acquisitions, and launching refrack campaigns, the discipline could see a lot of advances in 2016-17.
Combined with a focus on the easier targets – mature fields and vertical wells – the technique seems set to make at least some impact and become yet another factor helping the US to maintain production, with only modest declines in the short term.
“What’s important to remember is that in spite of the low commodity price, mature fields – they are more resilient,” Halliburton’s Miller told investors last month. And this resilience could become even more attractive to producers as they work out their strategy for the coming months and years.