How Halliburton’s new Rock-on-a Chip™ microfluidic device for improving fracturing fluid evaluation can help lead to better field productionBy Tracey Murray
Pairing horizontal drilling with multi-fracture completions launched the shale oil and gas revolution more than a decade ago, but decades of developing thousands of incremental improvements have made resource plays a global force in oil and gas production.
That pace of innovation also hasn’t slowed. If anything, the downturn of the last three years accelerated the search for better practices and new technologies which improve efficiency and boost production for oil and gas producers.
Halliburton’s new Rock-on-a-Chip™ microfluidic device for selecting optimal hydraulic fracturing fluid composition could be the next step in this evolution.
“We used the Rock-on-a-Chip technology to evaluate two types of fracking fluid. Based on the results of those tests, we ran a weakly emulsifying surfactant frack fluid in a 45-well field trial in the Eagle Ford shale. The result was significantly improved oil production compared to the other fluid commonly used in the play, which confirmed the effectiveness of using Rock-on-a-Chip technology,” says Dr. Liang Xu, the technology’s principle investigator at Halliburton.
The Rock-on-a-Chip™ evaluation and results are documented in a Society of Petroleum Engineers paper (SPE 169147-MS). The Rock-on-a-Chip microfluidic device is also a 2017 World Oil Award technology finalist.
For years now, the oil and gas industry’s approach to hydraulic fracturing has been moving beyond a “more water, more sand, and hope for the best” approach towards optimizing fluid systems under different reservoir conditions. This is made possible through a better understanding of what’s actually happening underground during the critical stimulation phase. Halliburton’s Rock-on-a-Chip™ device simulates this by recreating the formation matrix on a fingernail sized chip, which then serves as a tiny window for researchers to see how various frac fluid compositions will behave in the reservoir matrix.
“Using photolithography and etching techniques, most geometric features observed in shale formations can be recreated digitally on the Rock-on-a-Chip device,” Xu explains. Despite its diminutive size, the chip can incorporate a wide range of subsurface complexity. “Homogeneous and heterogeneous networks can be patterned to represent the formation matrix. Larger micrometer-sized channels can also be modelled to represent the natural or hydraulically stimulated fractures. This combination can therefore be used to study the complex hydraulic communication between the formation matrix and fractures,” Xu explains. Even the tactile feel of the formation and other tribological features can be recreated through additives or deposition of nanomaterials on the Rock-on-a-Chip’s interior surfaces.
Once the chip is prepared, oil is passed through it at specific pressures to further recreate reservoir conditions. At this point, a specific frac fluid can be injected in order to determine which cocktail of chemicals has the best ability to displace hydrocarbons. “The displacement pattern and efficiency are monitored and measured by a microscope and high-speed camera,” Xu says.
The SPE paper documents the testing of a frac fluid with a non-emulsifying surfactant additive versus one with a weakly emulsifying surfactant.
In low-permeability reservoirs, such as the Eagle Ford in Texas, the most commonly used frac fluid surfactants were non-emulsifying. A recent study suggested that a RockOn™ weakly emulsifying surfactant could be more efficient at mobilizing oil through the tight pores, which the Rock-on-a-Chip device evaluation confirmed. This evaluation led to the use of a weakly emulsifying surfactant in 28 Eagle Ford wells, yielding “much higher” oil and gas recovery, according the SPE paper.
Importantly, the Rock-on-a-Chip device fluid screening process takes just minutes to hours compared to the traditional “black box” methodology currently used to evaluate frac fluids. The process involves passing them through core samples from the formation which can take hours to days. Rock-on-a-Chip technology also reduces the costs of frac fluid additive optimization by avoiding destructive testing of formation cores. Less than 1 ml of fluid is needed for each test, which also reduces waste compared to traditional methods.
Rock-on-a-Chip technology has been in the making since 2013 and was patented in 2017. The positive results from the Eagle Ford field trial suggest that the heavy lifting of field testing is already in place, but there’s typically always some resistance to using new technologies.
As Halliburton migrates the Rock-on-a-Chip device use into western Canada, it’s looking to collaboratively work with producers interested in improving production from wells by using this technology. “Rock-on-a-Chip technology overcomes the shortage of traditional approaches with limited visibility inside reservoirs during fracturing and enables real-time visualization. It’s all about maximizing BOE of any frac fluid package and bringing down costs by replicating the formation as accurately as possible which can help our customers achieve better production results,” says Keith Murray, Country Manager for Halliburton’s Chemical Division. “Our customers are adapting to more efficient methods to complete their wells, and Rock-on-a-Chip technology has enabled us to adapt to our customer’s needs for a more efficient selection process as well.”
Beyond frac fluid testing, SPE paper 185884 shows the use of Rock-on-a-Chip technology to study well interference—fractures created in one well “communicating” with the fracture networks of nearby wells, adversely impacting production in all proximate wells. “Rock-on-a-Chip studies could also provide useful insights for infill drilling,” Xu says.