What's new in production

As everyone with even a casual interest in the subject is aware, water is the bane of hydraulic fracturing. The race is on to find water-free (and cost-effective, needless to say) alternatives, with no clear winner breaking out of the pack, so far. But, an interesting field of contestants—each with its own strengths—makes betting on the outcome a strong temptation. Disregarding some ideas at the fringe, here’s the current field, with thanks to George Moridis, of the Lawrence Berkeley National Laboratory:

Liquid CO₂/sand fracturing. This stimulation process is unique, in that no liquids remain in the formation following the treatment. Thus, the formation damage created by retained stimulation liquids, and the resulting adverse effects on the relative permeability (and, consequently, on gas production), are eliminated. The working fluid, carbon dioxide (CO₂), is pumped as a liquid, and no chemicals, gels, or water are used.

Straight nitrogen-based fracturing. The main types of nitrogen-based fracturing fluids are energized, foam, straight N₂ gas (mist), and cryogenic N₂ liquids. Nitrogen gas fracturing is used primarily for water-sensitive, brittle, and shallow unconventional oil and gas formations. The use of nitrogen prevents the swelling of clays (and their undesirable consequences on permeability and production) that evolves invariably following hydraulic fracturing with water-based fluids, such as slickwater.

LPG fracturing. LPG has been used as stimulation fluid for 50 years. The technology was developed for, and applied to, conventional reservoirs before being adapted to unconventional reservoirs. Since 2007, more than 1,500 applications of this technology have been reported in Canada and the United States, using gellified propane as fracturing fluid.

Fig. 1. A typical multi-radial propellant fracture pattern (left) vs. a typical bi-radial hydraulic fracture pattern (right).

LNG fracturing. Liquefied Natural Gas (LNG) as a carrier fluid for fracturing is a relatively new technology, developed in 2011. This was developed to find a non-aqueous, cost-effective fracturing fluid that would be available near wellsites. Unlike water, natural gas used as a fracturing fluid mixes with gaseous hydrocarbons and is readily soluble into liquid ones.

Propellant-based methods. Space limits a full examination of the advantages and drawbacks of all these methods. But, in the “this-seems-like-a-good-idea” department, propellant-based fracturing may be worth a closer look.

Solid rocket propellant. Perfectly named RocketFrac Services thought enough of the idea to construct a company around it. The company says it “…employs a propellant-based fracturing process that uses a uniquely formulated solid rocket propellant to generate high-pressure gases for fracturing rock formations.” It claims successful deployment in over 1,000 vertical wells, resulting in an average 225% increase in hydrocarbon recovery.

The company’s numbers underscore the difference between hydraulic fracturing and propellant fracturing (Fig. 1), a difference that would seem intuitively true to most people: Hydraulic fracturing generates ~35,000 kPa (~5,000 PSI) in 1-to-10 hours; propellant fracturing generates ~205,000 kPa (~30,000 PSI) in 100-to-500 MS. And, hydraulic fracturing requires a lot of expensive surface hardware to generate one-sixth the pressure.

What about proppant? Good question. The company says none is necessary and claims “…multiple ‘self-propping’ mechanisms.” It points to three separate effects of propellant fracturing that prevent permeable pathways from re-closing after the treatment:

• Local disaggregation. Rapid loading and fracture opening causes minor disaggregation or “rubbilization” at the fracture face. These small particles prevent fracture closure and act as a locally derived proppant.
• Fracture erosion. High-temperature, high-speed exhaust gases result in a scouring effect that erodes the fracture surfaces. This erosion results in opposing fracture surfaces having dissimilar geometries.
• Shear dislocation. Some mineback experiments have shown shear dislocation, in which the opposing fracture surfaces close offset to each other. This offset closure results in permeable pathways remaining open.

You also may be asking how all that pressure is directed to the right places. The company has introduced a tool with reusable, fully integrated wellbore isolation mechanisms. It also claims another necessary quality of the solid rocket propellant: a long-duration pressure profile. Stringing these tools together enables treatment of multiple zones in one trip.

Questions remain. Although a considerable amount of investigation has attended the subject of propellant fracturing, e.g., “Laboratory Testing and Finite Element Modeling of Propellant-Induced Fracture Propagation in Shale Reservoirs” (Wieland 2005), it doesn’t appear to have quite yet reached the degree of predictability that would be found in an operator’s comfort zone. Of course, that could change tomorrow, as experience accumulates and industry boffins beaver away at evolving it.

In handicapping the race, it’s also useful to remember that, in this industry, nothing stands still. Speaking of handicaps, water remains hydraulic fracturing’s biggest, but maybe that will change, as well. What will be tomorrow’s mainstream waterless fracturing technology? Stay tuned….