When Fracturing for Geothermal, Is Proppant Really Necessary?
Fracturing hot rock to create a geological water-heating system is like fracturing an oil well, but for a different purpose, so is proppant really necessary?
Pressure pumping looks like it will be an essential tool for building geothermal wells in hot rock, but will particles of sand or ceramic be in the fluid mix?
Field testing designs show there is a divide over whether those particles will need to be added to prop fractures in extremely hot rock that will be used to heat injected water.
On one side are those applying what has been learned from fracturing unconventional oil and gas wells where pumping proppant is a given to hold open fractures over the long term.
When Fervo Energy fractured a horizontal well in hot, hard rock at its Nevada test site, it pumped 7.3 million lb of sand, mixing 40-70 and 100 mesh, according to a paper presented at the recent 48th Workshop on Geothermal Reservoir Engineering at Stanford University.
On the other side are those who argue that the pressure of water injection—either above or below fracture opening pressures—is a better option for maintaining flow paths.
There are a couple of explanations for how fluid flow alone would work, said John McLennan, who is working on reservoir management at Utah FORGE.
"Some believe that injection at rates below closure pressure causes shearing at fracture faces, leaving rough faces that maintain flow paths,” which is called self-propping, he said.
Others argue that fractures can be kept open with higher water-pressure levels—without proppant—which they call hydro-propping, according to a paper from the Los Alamos National Laboratory presented at the Stanford workshop.
At the FORGE test site, nothing was pumped to prop open fractures during its three-stage test. There was a small volume of microproppant added to the fluid on the third stage. The SPE paper describing the completion offered two reasons for using grains at the smallest end of the broad 100-mesh spectrum, neither of which involved propping open fractures (SPE 212346).
One was to provide evidence of fracture connectivity if grains are found in the second well drilled. The other possible benefit was the grains might encourage simpler fracture development by blocking off tiny natural fractures that could divert the flow from larger fractures.
In the US, what has been learned from fracturing wells—particularly over the past 10 years—provides a lot of ideas for those trying to create well-to-well fracture networks in hard, hot rock for heating water.
The proppant divide is an early sign that geothermal developers will likely be picking and choosing from oilfield completion methods based on what it will take to create a long-lasting water-injection network through hot, dry rock.
Water injection into those fractures provides a steady level of pressure to keep the cracks open. Based on the 50,000 B/D capacity of recent injection wells, that would amount to nearly 35 bbl/min. That is the rate used at Forge to stimulate two of its three stages, but the water would flow past many stages.
In a shale well, the natural pressure drops rapidly from day one and proppant is needed to maintain those flow paths. At oilfield test sites in the Eagle Ford and Permian, it has also been observed that proppant is often irregularly placed, with a lot in a few spots and none elsewhere. Over time, the grains can get embedded in the rock or a proppant pack can get clogged by scale.
The paper by researchers at Los Alamos put hydro-propping on the list of four ideas they said could help make hot-rock geothermal injection economically viable.
The paper argued that hydro-propping in a hot-rock injection well is a better option than buying and pumping sand. To do so, it said that relatively high injection levels were needed for hydro-propping, which raises the risk of water leaking out into nearby faults, some of which may be prone to shifts that cause tremors.
To limit the risk of earthquakes in seismically active spots, the paper advised the use of “fracture caging.” The goal is to use “production wells around a geothermal injection zone to contain fluids” injected into the fractured rock to limit the risk of leakoff-induced seismicity, according to this paper by Luke Frash, the lead writer of the Los Alamos paper.
There are practical problems with proppant in fractured hot rock, according to papers that come at it from a variety of angles.
The FORGE paper noted that if small grains of proppant are freed by the flowing water, they could cause damage if they flow out with the heated water and end up in the turbines powering electric generation.
“With surface power generation infrastructure, there could be zero tolerance for future solids, such as proppant,” the authors wrote.
On the other hand, a study from Halliburton suggests free particles of sand or ceramic might not be likely because under those conditions, the particles in the proppant pack could be fused. It describes how the heat and pressure can accelerate diagenesis—the geologic process that slowly creates rock (SPE 98236).
It cited lab testing showing that the minerals in particles placed in an HP/HT fracture can speed the reactions involving mineral-rich water found in the ground. The paper cited a test where the porosity was reduced to 15% of the original level in less than a year.
The paper was based on the conditions in oil and gas wells, which are not as hot as the geothermal wells, but there is more mineral-rich water in those reservoirs compared to the dry, hot rock targeted for geothermal. The paper recommended coating the grains with a film that would repel water, which triggers diagenesis.
In a geothermal well, those grains would need to stand up to higher heat than found in the hottest shale wells, and last far longer since geothermal projects are built to power large industrial plants built to last decades.
“It is going to need to hold up to the temperatures for 30 years of life. That is pretty extreme conditions for proppant,” McLennan said.
For Further Reading
SGR-TR-224 A Proposal for Safe and Profitable Enhanced Geothermal Systems in Hot Dry Rock by Luke P. Frash, J. William Carey, Bulbul Ahmmed, et al., Los Alamos National Laboratory. firstname.lastname@example.org
SPE 98236 Fracture-Related Diagenesis May Impact Conductivity by Jim Weather, Mark Parker, Diederik van Batenburg, and Phillip Nguyen, Halliburton.