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A lot has been written in recent years about water usage in hydraulic fracturing, by both popular and trade press writers (including this one). In some shale regions, water is the number one issue, surpassing greenhouse gas emissions, groundwater contamination and earthquakes as the central focus of public criticism. That would certainly be true in Texas’ Eagle Ford shale, because water is an especially precious commodity in that particularly arid eco-region (known officially as the Tamaulipan Mezquital), and also in parts of the Bakken.
Napalm. So-called “waterless” fracturing technologies, as well as hybrid and water-reducing solutions, are receiving increasing attention by the industry. These include techniques using high-pressure nitrogen and CO2, and others utilizing propane and butane gels. In the first experimental frac job in history, in Hugoton field, Kansas, in 1947, Halliburton engineers injected gelled gasoline—essentially napalm—into the formation to try and stimulate gas production. Results were reportedly mixed at best.
Today, gasoline fracturing would probably not be considered particularly green. But there are situations where a water frac—literally hydraulic—is not desirable, because the water tends to swell the formation, increase surface tension and reduce gas production. Particularly, this has been the case in certain formations in western Canada (the Cardium, for example), where GasFrac Energy Services has used liquefied petroleum (mostly propane) to energize foam for over 2,000 fracturing jobs (see “What’s New in Production,” May 2013). The process employs iron sulfide and phosphate ester to turn the LPG into a gel for fracturing. Magnesium oxide is used to break the gel back into a liquid. These chemicals are non-toxic in the amounts utilized, according to the company.
In South Texas, BlackBrush Oil & Gas has been using LPG gels to fracture wells in the San Miguel, Buda and Eagle Ford formations, and has claimed production increases averaging 77%, at least initially. The company reports that after the first year, production drops back to near the rate expected from a conventional hydraulic fracture, but there is a net production gain.
GasFrac is reportedly testing a “hybrid LPG” system that allows more proppant to be delivered downhole, resulting in a larger fracturing area.
Getting colder. Another waterless alternative is cryogenic nitrogen. Halliburton did some experimental fracturing in the Devonian shale of West Virginia in the 1990s, and results were promising: “With proper engineering, liquid nitrogen can be used safely as a hydraulic fracturing fluid. The fluid’s extremely cold temperature (–300° to –320°F) will induce thermal tensile stresses in the fracture face.” These stresses are greater than the tensile strength in the shale, therefore the fracture face fragments. The report goes on to say that the extreme cold causes water to freeze instantly, so that ice can be used as a diverter between fracture stages (SPE 51067).
Cryogenics is an old and fascinating science. It was noted centuries ago that substances behave very differently when subjected to very cold conditions. The generally accepted definition of a cryogenic gas is one that has been cooled to a liquid form below 150 K (degrees above absolute zero, equivalent to –189°F. The Kelvin scale isn’t normally used with a degree symbol). Nitrogen, first liquefied by Polish scientists in 1883, boils at 63 K. Working with the stuff is tricky—for pumping liquid nitrogen, the wellhead and surface manifold must be made from stainless steel. In theory at least, as the liquid N2 warms, it expands by eight times, flowing out with no damage to the formation and no loss of productivity. The technology is still in development.
Super, meta and quasi. A gas that is very cold, but above its boiling point, can still be useful in fracturing. Expansion Energy has proposed what it calls VRGE non-hydraulic fracturing. The system uses cryogenically processed natural gas, either from nearby sources or from the target formation, to energize the fracturing foam and deliver proppant. In this case, “cryogenically processed” does not refer to LPG, but to gas chilled below –150°F.
Expansion Energy’s chief technology officer, David Vandor, spoke at World Oil’s ShaleTech Conference earlier this year. He explained that what he calls CCNG (cold compressed natural gas) is gas in a “metacritical” state, that is, gas that is colder than “supercritical” (the point above the critical state where phases like gas and liquid do not exist), but under higher pressure, becoming something like a “dense fog.” CCNG requires much less energy to pump—not a liquid, but behaving in many ways as a liquid.
This “quasi-liquid” CCNG is pumped to high pressure, then expanded into high-pressure CNG before being blended with small amounts of water to create a “gas-energized” fluid to fracture the formation and deliver proppant. Many of the additives used in conventional fracturing are there to protect the formation from the swelling effects of water. The VRGE system avoids use of these chemicals. The gas is not at cryogenic temperatures downhole, so there is no need for specialized casing.
The natural gas used in fracturing becomes part of the total gas inventory. “The gas that you use to create the process comes back. That’s a good thing,” Vandor said. “What you’ve done is loan the natural gas to create the process—you didn’t use it up.”
The CCNG is produced at the surface, using about 10–15% of the natural gas as fuel. The rest will eventually return, and can be sold. The same equipment used to make the CCNG can also serve to separate the natural gas liquids from the gas stream, and to produce LNG for transport.
Field tests will be required to determine economics and feasibility. Meanwhile, the quest to kick water entirely out of the mix continues. 
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