New Testing Facility Built To Prove Whether Natural-Gas Foam Is Shale Sector's Next Fracturing Fluid
A 6-year R&D project concludes with the completion of a technology kit designed to study how combining highly pressurized natural gas and water could be a holistic alternative to traditional hydraulic fracturing.
Foam made with natural gas could one day help US shale producers overcome two of their sector’s oldest and most inherent challenges: a heavy reliance on water supplies for hydraulic fracturing and the flaring of uneconomic associated gas.
This is the big idea behind a 6-year project led by the Southwest Research Institute (SwRI) in San Antonio, Texas. The nonprofit applied-research group announced the project culminated this week with the completion of a pilot-scale system built to study how natural-gas foams perform under different pressures and temperatures.
“The foam is created by jetting the natural-gas stream into the pressurized water,” explained Griffin Beck, who added, “The process utilizes up to 80% less water than typical fracking treatments.”
Beck is the project’s principal investigator at SwRI and hopes that a commercial version eventually makes it to the field one day. Such a system would enable operators to create foam at the wellsite, using their own field-gas and produced water. Ideally, this would displace flared volumes and the need to truck in as much fresh or recycled water from more distant sources.
Since it began in 2014, the research and development project received more than $2.6 million in funding from the US Department of Energy. The emerging-technology arms of Schlumberger and Chevron provided additional funding and technical support.
SwRI describes the test facility as a “single-pass pilot plant” that can characterize foams at pressures up to 7,500 psi and temperatures as high as 300°F.
The main component of the facility is a pressure vessel made of 10- to 18-ft-long test sections that can be run at inclinations ranging from 30° to vertical. This feature helps simulate the differences between flowing foam through the lateral and vertical sections of a horizontal well.
One key driver for the large-scale system boils down to the fact that the type of experiments needed to fully understand the unproven approach are either too difficult or impossible to do in a traditional laboratory.
The project also focused on using a garden-variety compressor to pressurize the natural gas before it is mixed into a foam. Oilfield innovations that rely on so-called “off-the-shelf” technologies are considered to have a leg up in terms of adoptability and scale.
Another highlight of the testing technology is its microscope-equipped sight glass that allows the researchers to see what's going on during the high-pressure test runs. Images taken from this setup are analyzed by a custom-designed algorithm to make lighter work of measuring the foam's bubble sizes, their distribution, and even their texture.
That analysis has led SwRI to conclude that its various formulations of natural-gas foam are most durable at temperatures of 250°F or below. The more the mercury rises above that threshold, the faster the foam breaks down as small bubbles rapidly merge and become large bubbles.
Other testing has shown that the viscosity of natural-gas foam is otherwise stable enough to transport sand from a wellbore into a tight-rock formation.
SwRI also said the foam will generate less water-induced clay swelling that can block hydrocarbons from flowing out of a tight reservoir’s narrow pore throats. This benefit is generally supported by the industry's experience using foams made from other gas types.
A reservoir model developed by the researchers suggested that their reservoir-friendly foams may yield a 25% improvement in cumulative production compared with water-based stimulations.
The SwRI research team and its partners shared many other details about the technology late last year in a technical paper (SPE 201611) selected for presentation at the SPE Annual Technical Conference and Exhibition.
In the paper, it is noted that while there are patents on natural-gas foam fracturing and that there is at least one ongoing study launched by a Canadian producer, its execution at any significant field level is not reflected in industry literature.
The effects of common additives such as guar and the varying properties of produced water are also discussed in the paper.
Foams, also called energized fluids, have been used in hydraulic fracturing operations for decades. But with few exceptions, this long history involves fluid systems based on either liquid nitrogen or carbon dioxide.
Supply bottlenecks, questions over cost, and geologic limitations have all combined to relegate foam fracturing to a relatively niche status since it was first introduced in the US more than 50 years ago.
Other Capabilities of SwRI's Foam-Testing Facility
- In addition to methane, system is compatible with nitrogen foams with aqueous or petroleum-based fluids.
- Foam generation up to 2.5 gal/min
- Foam texture, foam half-life, rheology, pressure transmissibility, heat transfer, and foam stability measurements
- Simulated wellbore test fixture for drilling or production analysis at field conditions, with optional fluid-recirculation capabilities
- Gas-kick and gas-migration testing
For Further Reading
SPE 201611 A Pilot-Scale Evaluation of Natural-Gas-Based Foam at Elevated Pressure and Temperature Conditions by Griffin Beck, Southwest Research Institute, et al.