Suppliers, researchers and service companies working in unconventional oil and natural gas plays look to displace large volumes of hydraulic fracturing water with energized fluids and foams. This fracturing solution has been underutilized in the U.S. since the inception of slickwater, which is a water, sand and chemical mixture.

Now, with comparison studies in Canada, as well as pilot operations in the Marcellus and Eagle Ford plays boasting reduced water and proppant consumption in addition to increased recovery rates, interest may be rising in adopting energized fracture treatments in unconventional U.S. plays.

Energized fluids and foams are primarily composed of compressible gases such as carbon dioxide (CO2) or nitrogen (N2). Gas content is used to distinguish energized fluids from foams. Energized fluids contain less than 52% gas content, energized foams contain 65-75% gas content, and high-quality foams are composed of 95-99% gas.

A recent IHS report, “The Future of Water in Unconventionals: Water Management Strategies,” concludes that developments in energized foam have potential, but face higher costs and added operational complexity when compared to established water-based fracturing technologies.

A robust market for energized fluids and foams exists in Canada. The Journal of Petroleum Technology (JPT) estimates that of horizontal shale wells completed in the past year, 40% of wells in Canada use energized fluids and foams, versus roughly 2% of wells completed in the U.S. The journal also cites a comparison study carried out by Murray Reynolds, director of technical services at Ferus, an oilfield cryogenics supply company. Reynolds concludes that energized fracture treatments were 25% cheaper and consumed 80% less water than slickwater treatments in the Montney shale tight-gas formation that straddles the Canadian provinces of British Columbia and Alberta.

Canadian operators and engineers are able to complete such a large portion of their horizontal wells with energized fluids due to their familiarity with the technique and a strong supply network. The limited use in the U.S. has largely been due to the success of slickwater.

Oil service company Baker Hughes’s experience with energized fracture treatments in the Marcellus and Eagle Ford basins has been instructive. Its pilot operations are demonstrating how energized fracture treatments can benefit U.S. operators. Its VaporFrac technology uses gas content up to 95%. In practice, ultra-lightweight proppants are dispersed in the liquid part of the mixture. As the amount of proppant required is proportional to the amount of liquid in the mix, the company's method reduces the amount of proppant used.

In the Marcellus, the VaporFrac technology was deployed in the same well where slickwater was in use. Operators chose an energized fracture treatment to stimulate the end of long horizontals, known as the "toe" section of the well, after experiencing difficulties with slickwater. Satya Gupta, a business development director at Baker Hughes, says that the company's foams have better proppant transport than slickwater. The pilot operation seemed to prove his claim as the toe section was successfully stimulated using VaporFrac technology.

In the Eagle Ford Shale another story is being told, however. Attempts by Baker Hughes to boost production and reduce dependency on hydrocarbon-based fracturing oils proved to be less economical. The experience suggests that although the technology is able to increase production in low-pressure wells and in formations where water trapping is an issue, logistics and economics don’t always favor energized fracture treatments. In order to be adopted as a successful technique, fluids need to be readily available and affordable so that increased production offsets added expenses.

The pilot projects suggest that location and timing are important if energized fracture treatments are to be more widely used in the U.S.

First, reservoir attributes must favor their use. The JPT finds that energized fracture treatments are commonly used in low-permeable, under-pressurized wells. Injecting gaseous media maintains reservoir pressure and retains permeability. The treatments are also favorable in dry well formations where saturating the formation can lead to clay swelling or water loading that inhibits the flow of hydrocarbons.

Conversely, the JPT found that over-pressurized formations do not favor energized fracture treatments. Slickwater treatments first replaced energized fluids and foams 20 years ago when poor results were experienced in the Barnett Shale, a brittle and over-pressurized formation. High volumes of fracture fluids introduced through slickwater proved to be a better solution. Issues also may arise with CO2, known to react and damage formations as a result of issues related to asphaltenes and paraffin.

Second, water economics play an important role. Sarah Fletcher, senior research analyst at IHS, describes the risks associated with water scarcity which impacts 70% of unconventional wells in the U.S. Drought-stricken areas or locations where produced or flowback water disposal costs are high can benefit from energized fluids and foams. The JPT reports that flowback water accounts for 10-20% of injected fluids. What's more, water treatment plants can offset a relatively small portion of completion fluids needed for future wells. If water sources are limited and costly, energized fracture treatments may become more desirable.

Therefore, Reynolds predicts a slow increase of energized fracture treatments in the U.S. over the next 10 years.

Additional Resources: IHS Unconventional Energy Blog; IHS Unconventional Solutions