Operators are using more proppant and more clusters to increase production. Yet decline curves can be steep. One problem is that the proppant may not end up in the desired location.

Enter the nanoparticle.

David Holcomb, a consultant and founder of Pentagon Technical Services, worked with Nissan Chemical America Corporation scientists to develop a nanoparticle dispersion, nanoActiv HRT (hydrocarbon recovery technology), that will diffuse into the reservoir’s natural fracture network, dislodge the oil from the reservoir, and separate and reduce it into smaller droplets for easier production.

Holcomb describes how the nanoparticles work thusly: “Diffusion is the way they get there, disjoining pressure is what they do when they get there, and fragmentation is what allows the oil to more easily move back to the wellbore.”

Yusra Ahmad, an oil and gas research scientist with Nissan Chemical, was involved in lab testing the technology.

“Don’t confuse nanoActiv HRT with a surfactant,” she says.

“The mechanism of action between the two is very different. Surfactants work chemically and nanoparticles work mechanically.”

The nanoparticles are sent downhole in a pre-packaged pill with a colloidal solution before the well is hydraulically fractured.

“The slick water pushes it further into the reservoir, and when you pump the frack pad, it sends the pill beyond the reach of the general fracture, so you get more interaction with your reservoir, which helps with increased production,” Ahmad says.

The nanoparticles diffuse rapidly into the reservoir. There are no adverse adsorption or wettability issues, so they can work in any type of reservoir, according to the manufacturer.

Holcomb, referring to the formulae used to determine rates of diffusion, says the nanoparticles “appear to break Fick’s law of diffusion by orders of magnitude.” A slug of 500 gallons of nanoActiv HRT can treat millions of square feet of reservoir.

“Understanding how the nanoparticles in nanoActiv HRT behave has been difficult because they’re small and difficult to observe,” he says.

Inspired by scientist Dr Darsh Wasan’s groundbreaking work on disjoining pressure and fragmentation, Holcomb worked with Nissan Chemical to adapt and improve the technology for oilfield use.

Testing revealed that the nanoparticles fragmented oil into much smaller droplets. The smaller droplets of oil flow more easily through the reservoir and fracture network.

The nanoparticles wedge themselves at the three-phase contact angle to create the disjoining pressure, which dislodges the hydrocarbon off the surfaces of the reservoir. The nanoparticles encase the newly mobilised hydrocarbon and fragment it.

“We’re still trying to learn why this fragmentation happens,” Holcomb says. “The nanoparticles will surround whatever liquid hydrocarbon they come into contact with and break it into smaller droplets.”

Holcomb says the nanoparticles have also been known to break down paraffin and other heavy hydrocarbon deposits, allowing them to be more easily removed from the reservoir or wellbore.

The nanoparticles go after and break down fluids and gases in the reservoir in order of density, from lowest to highest—for example, gas all the way up to brine.

Nissan Chemical is working with Linde Corporation to further develop nanoparticle dispersion technologies and industrial gases specifically designed for natural gas as well as oil wells.

NanoActiv HRT is a dispersion of surface-modified silica nanoparticles dispersed in water designed to withstand high salinity. A high-temperature version of nanoActiv HRT is rated to 350 degrees Fahrenheit. The technology is compatible with all frack fluids, Holcomb says, provided the nanoActiv HRT is placed in a fresh water pill and preceded and followed by a small fresh water spacer.

“Because there’s so much surface area in a given volume, you can design the nanoparticles to increase the efficiency of any application. You can optimise not just completions, but also (enhanced oil recovery), remediation, et cetera,” Ahmad says.

NanoActiv HRT has seen a number of deployments for remediation.

“Our laboratory has essentially been the Permian basin, and we have recently started in the Bakken and D-J basins,” Holcomb says.

A deployment in a Niobrara reservoir revealed a “persistence effect” that significantly slows a well’s natural rate of decline.

“We don’t know how long the effect lasts because we only have about two years of data,” Holcomb says.

Some of the first commercial deployments of the nanoparticles were in Texas wells in the Wolfberry formation. In one well, nanoActiv was introduced at the outset, and it flowed almost seven months before the operator put it on a pump to drive up output.

This well, Holcomb says, reflected a reduced decline curve of only about 39% compared to untreated wells in the field, which showed an average decline curve of 60% decline over an annualized period.

In another Wolfberry well, the operator added an electrical submersible pump to a treated well after three months. After 241 days, this well was performing nearly 225% better than a group of offset wells, Holcomb claims.

“Recent data from horizontal well applications reflects an average of 20% to 30% higher (barrels of oil equivalent) than direct offsets over a one-year period with a typically higher oil cut and/or a lower decline rate,” he says.

As of early October, the technology had been used in more than 48 wells to treat nearly 2000 stages. In one deployment, it was run in a well with 62 stages.

In the future, it may be possible to learn more about why some nanoparticles remain in the reservoir while some flow back to the surface with the produced fluids.

“Such low volumes are required for an effective treatment, so there’s little chance you’d see them,” Ahmad says. “But we want to know more.”