Horizontal drilling and hydraulic fracturing have boosted oil and gas production to new heights in the U.S., but cryogenic fracturing could lift sagging recovery rates, prolong the life of fields and reduce use of what is becoming a more precious commodity.

By replacing water with cryogenic fluids, such as liquid nitrogen or liquid CO2, researchers hope to provide operators of gas fields with a new well stimulation technique with multiple benefits. Researchers at the Colorado School of Mines, working with CARBO Ceramics, Pioneer Natural Resources and the Lawrence Berkeley National Laboratory, are testing various approaches as part of a $2.7 million project with the Research Partnership to Secure Energy for America (RPSEA).

With a goal of significantly increasing permeability in a large reservoir volume surrounding vertical and horizontal wells, RPSEA said the benefit of the project will be twofold if successful.

“First, it would reduce or eliminate the water usage during hydraulic fracturing, which has clear environmental benefits including reduced groundwater pumping and eliminating flowback disposal that sometimes leads to induced seismicity,” said Kent Perry, vice president of onshore programs for RPSEA. “Second, from production’s point of view, it should reduce or eliminate formation damage caused by capillary trapping of fracturing fluid and/or interaction between fracturing fluid and clay.”

As part of the three-year project led by Yu-Shu Wu, professor and foundation CMG reservoir modeling chair at the Colorado School of Mines’ Petroleum Engineering Department, two sets of lab experiments are being conducted. The first investigates the cryogenic fracturing process at room temperature, using isotropic media; the second uses natural rock and core samples under reservoir temperature, stress and pressure conditions. Both sets will test the potential of liquid nitrogen and CO2. A triaxial loading frame is being used to simulate downhole stress conditions.

As of mid-third quarter, researchers have conducted fracture initiation tests in transparent acrylic and glass samples, concrete blocks and sandstone blocks. They also have designed and built cryogenic fluid delivery systems, a loading frame and acoustic sensors for monitoring and detection, in addition to the capability of injecting pressurized liquid nitrogen and nitrogen gas, according to an emailed response jointly from Perry and Wu.

“We are about to start cryogenic fracturing fluid injection test in the next few weeks,” the researchers said. “So far we only tested liquid nitrogen. This fluid is easily obtainable, boils rapidly, cools rock quickly and is nontoxic.”

The most significant finding so far, according to researchers, is that “cold temperature can initiate complex fracture patterns on the surface of a sample.”

But the team also has encountered some challenges. These have involved the availability of pressure equipment and seals rated for liquid nitrogen temperature and use of stainless steel and proper designs to direct the cold temperature to where it is needed, such as the rock’s surface rather than to seals where it could be harmful.

“In the field, there will be challenges in delivering liquid nitrogen to the depth needed, but there is industry experience in that field,” the researchers said. Transporting proppants could pose additional challenges. “The proppant-carrying ability of liquid nitrogen is not as strong as other fluids, and it will vary because of changes in gas state and velocity. We think some kind of proppant will be needed to keep the fractures open, and this will be explored by the experiments.”

It is still too early to say which types of formations cryogenic fracturing would best suit, “but intuitively those with low thermal conductivity and high thermal expansion coefficient would be more amenable to cold temperature induced failures,” said the researchers. “Also, brittleness will help just like the case for regular hydraulic fracturing.”