Stressed US shale drillers are finding solutions to precipitous production curves. Ros Davidson explores the latest choking, artificial lift and gas technologies which are helping them play the “waiting game”
In the beleaguered US shale industry, production optimisation techniques are being scrutinised more closely than ever. Yet technology which can aid the so-called “waiting game” – holding production at certain levels until a rise is needed – is also catching industry attention.
Interest has grown in techniques which can flatten the production curve of shale wells. As well as improving ultimate recovery volumes, these can also help limit damage to the well, to local wells and to the reservoir, which can be depleted too quickly, especially with shale wells’ famously rapid rate of decline.
These techniques, such as the use of chokes to preserve pressure, can also allow a producer to leave oil or gas in the ground until commodities prices rise. This is especially useful if there is too little midstream infrastructure, such as in the Marcellus formation.
US oil and gas production may have decreased because of the oil rout, but that has been almost entirely offset by a very dramatic rise in per-well production in shale plays. In fact it has surely been what Andrew Grove, co-founder of Intel, would have described as a “strategic inflection point” – when a major change occurs in an industry’s competitive environment.
For example, in the Eagle Ford shale play in south Texas, production has risen by a factor of four in the last five years as a result of improved hydraulic fracturing completion practices, Professor Mukul Sharma of the Department of Petroleum and Geosystems Engineering at University of Texas, Austin, explained to InnovOil.
Moreover, since 2014, there has been a 12% improvement in production efficiency because of high-grading – finding the best places to drill – and 10% because of in-field improvements, according to consultancy IHS. “So we are more efficient, though production may decline,” said Reed Olmstead, the group’s manager of North American supply analytics in plays and basins. “Had the industry not become more efficient, it would have either spent more money, or production would have declined more, or both,” he added. “US$100 oil covers a lot of mistakes.”
Hurry up and wait
Two in-field techniques that have received much recent attention in shale are artificial lift and choking. “Proper design of artificial lift and proper choke management can increase production by 50-100%,” Sharma estimates.
Artificial lift to maximise output and extend the life of wells has been employed for decades in conventional wells, but it is no trivial matter to use it successfully in horizontal wells, he continued. The uneven flow in fracked wells tends to cause problems for artificial lift when it is installed after six to 12 months. Liquid can pile up, for example, if lift is not performed correctly.
Concerns over how to install pumps, what kind of lift techniques – e.g. gas lift or electrical submersible pumps – are vital, given the variation in geometry and volumes of fluid in a fracked horizontal well compared to a vertical well, Sharma explained. With pressing demand, he added that most service companies were apparently working on new downhole pumps, including Schlumberger, Weatherford and Halliburton.
There is an art to integrating artificial lift with well and reservoir design. A vertical section can be created at the “heel” of a horizontal well, for example, to create a sump so that liquids can be lifted more easily, Sharma said. About half a dozen companies, including the aforementioned service majors, are working on this specific issue.
One of the greatest challenges with artificial lift design is predicting multi-phase flow calculations, which can be so imprecise they are off by a factor of two to three, he noted. PipeFractionalFlow, a spin-off of Sharma’s research team at the University of Texas, has just commercialised software for multi-phase flow modelling that he claims can improve predictions to within 15-20%.
For some, artificial lift has been a port in a storm. Baker Hughes said that its artificial lift business was the “one notable exception” to an oilfield services sector-wide slump in the first quarter of 2016, growing by 4% even as other shale-related revenues fell 10%. The economic argument is persuasive for shale drillers who can afford it – while drilling and fracking a new well can cost several million dollars, a US$250,000-500,000 artificial lift programme can push production back to 50-75% of its initial rate, Evercore ISI analyst James West explained to Reuters in a recent report.
Another method of flattening the curve is choking – essentially restricting hydrocarbon flow with control valves – a process used to some degree on most wells. A major realisation in the last two to three years is that if a choke is properly managed, it “significantly” improves shale well production over the short and long term, Sharma said.
Yet choke management when well production is increased or brought back on line is tricky. Do you open it up quickly or gradually? Sharma’s team has developed Choke Manager, a combination of software and a general methodology designed to help determine the best choke strategy for a producer to maximise oil recovery. In the last few weeks, it has been made available for testing to two industry partners, who are operators, and it is now being marketed to service companies.
More aggressive choking has been employed in the Marcellus by Chesapeake, where the first-year well decline rate is 50-60%, says IHS’s Olmstead. Continental Resources is also using more aggressive chokes at three news wells in the STACK play in Oklahoma.
The Haynesville shale has an especially dramatic decline rate of 70-75% in the first 12 months. Aggressive choking there can be inferred from changes in an operator’s decline rates. Encana, which has gone from about 80 to 10 wells in the play, has changed its average decline rate from 68% to 28%, according to IHS data. Exxon/XTO’s has declined from 52% to 39% in the Haynesville, whereas BHP and Anadarko’s have stayed relatively flat, Olmstead added.
Unconventional well design is generally taking strides forward. Should it be toe up or toe down, should the bore tilt up or down and should it be drilled in the middle, bottom or top of the pay zone? How much fluid and sand should be used; should the fluid be more viscous or less so; how fast should the fluid be pumped? There are perhaps two dozen variables that can be adjusted.
In many ways, hardware, downhole tools and chemicals have been improved. There is the well-known use of longer laterals, more fracking stages and proppant loading, the use of slickwater – and thus there is less reliance on pricey chemicals and a better environmental outcome – and sliding sleeves during fracking, such as those made by Schlumberger.
“Wells continue to improve because of longer laterals and proppant loading. However, the rate at which they’re improving is starting to even out, as the industry is largely reaching the limits of the benefits from those practices,” said Olmstead. For example, laterals have doubled in length, to say 10,000 feet (3,000 metres), compared to a few years ago.
There is also interest in increasing the use of microseismic data and 3D seismic data, said David Burnett, director of technology at the Global Petroleum Research Institute, Department of Petroleum Engineering at Texas A&M University, in an interview with InnovOil. In addition, there are even newer techniques such as two-screw multi-phasic pumping, which over the life of a field can help accommodate fluctuations in oil well viscosities, water cuts, gas-to-liquid ratios and gas volume fractions. Burnett listed Colfax Fluid Handling in particular as one provider of the technology.
Flowback water recovery is improving, and recycled frack water is being increasingly used in as many as 30% of wells, said Burnett. This has helped the economics of some gas fields in the eastern US, where water disposal is especially costly. One recent study suggests that, based on field data, only 2-26% of fracture fluid is recovered during flowback in Marcellus shale wells in West Virginia.
Flat lines, for taking water to the wellhead, reaching up to half a mile per coil, are being used. Flare gases are being collected and monetised – and emissions are reduced – and there is a strong push to use liquid nitrogen and/or CO2 in place of water and chemicals for fracking. The technique has gained particular support from Air Liquide.
In addition, a dynamic gas-blending kit designed by Caterpillar Global Petroleum allows for the use of natural gas instead of substitution of diesel fuel during high-pressure pumping for fracking, with Burnett estimating that around 25% of companies are considering such an investment.
With prices under pressure but looking relatively stable for now, the focus on optimisation is unlikely to retreat in the short to medium term. With proven interest from service companies, one can be sure that a new wave of improved choking and lift equipment is already in trials, as producers pursue an even flatter shale curve. Indeed, as Deloitte Centre for Energy Solutions director Andrew Slaughter predicted in a recent Reuters interview: “The low price environment will give companies and operators a chance to take stock of the techniques that work… Production optimisation is going to be the next phase of the shale revolution.”