Energized Fracturing Solutions

The combination of horizontal drilling and hydraulic fracturing made possible the shale revolution that is seeing thousands of horizontal wells drilled and completed annually. The most common extraction process uses water-based formulations to achieve sufficient viscosity or velocity to suspend and place a proppant.

Water-based fracturing with fluids can leave liquids trapped in low-permeability, tight, depleted or water-sensitive formations. Water initially seemed cheap, readily available and forgiving. Water’s original attractiveness as the ultimate fracturing fluid became conventional wisdom and evolved as unconventional resources did.

However, water life-cycle costs have risen significantly, particularly in areas experiencing shortages or those with fewer regional disposal well options. At the same time, public awareness and subsequent negative perception of the sheer amount of water required for each well, typically between 2.5 million gallons and 5 million gallons (and as high as 10 million gallons) led some communities to
require producers to disclose consumption figures.

Energized extraction solutions
When it comes to hydraulic fracturing, there is significant room for improvement in productivity and also to reduce costs. Pumping more sand and fluid into longer laterals is not necessarily the most strategic approach. While bigger might sometime be better, in this case it does not result in optimal wells.

The use of nitrogen (N₂) and CO₂ overcomes and mitigates many of the challenges associated with traditional water-based hydraulic fracturing fluids by reducing the high volumes of water, chemicals and proppant. The use of CO₂ to displace water in hydraulic fracturing continues to be a proven method used in well stimulation of reservoirs from Saudi Arabia to South Texas.

Energizing solutions using CO₂ or N₂ provide a better approach for operating companies to increase oil and gas production from tight or water-sensitive formations as well as unconventional reservoirs such as shale, tight sands and coalbed methane.

N₂ as an alternative to CO₂ for well stimulation has proven effective for well stimulation of shallower reservoir environments. Nitrogen hydraulic fracturing formulations include using 100% N₂ for total water replacement to creating nitrified slick water or foams for well stimulation to improve productivity and reduce water footprint.

When injected into oil and gas wells, these energized solutions are able to enhance hydrocarbon production rates and yield improved long-term economic recovery over the life of the well. Fracturing treatments energized with CO2 or N2 are increasingly being recognized for maximizing long-term well productivity as a result of minimizing environmental damage with smaller wellsite footprint sans large water retention pond requirements. They also reduce the overall costs of water transport, treatment and disposal.

A well-designed energized treatment can in fact be more economical than water while also being more reservoir-friendly. Energized treatments place significantly less water into the reservoir. The use of water also can take up valuable time during flowback, causing increased time to clean up the water pumped downhole.

Recent studies indicate that, from an economic perspective, hydraulic fracturing with solutions energized by CO₂ or N₂ can achieve significantly more hydrocarbon recovery than nonenergized approaches. One such study found that use of energized fluids improved well performance by up to 2.1 times compared to nonenergized solutions.

Energizing the fracturing fluid with CO2 or N2 also improves the total flowback water volume and rate, minimizes fluid retention and reduces the required water volume, which can have significant economic implications. Critically, energizing fracturing fluid also helps avoid damage, defined as “any induced reservoir change that inhibits or restricts hydrocarbon flow during well stimulation.”

Additionally, the flexibility of energized solutions allows the hydraulic fracturing fluid to be mixed according to the technological needs of unconventional reservoirs. They provide more rapid and complete treatment fluid recovery, help to clean without the need for swabbing and reduce formation damage by minimizing the amount of aqueous fluids introduced to the formation.

Economics
To realize the full potential value of an oil field and to achieve the highest recovery factor, using energized fluids during each stage of the recovery process is the best way to achieve optimal results. But achieving a field’s full potential value also means optimizing recovery along with the costs of that production. Energized fluids offer the means to maximize the recovery factor and, importantly, if planned from a fieldwide perspective, the means to optimize the cost of production.

To strive for the greatest EUR of the well in the most economically effective way, both performance and economy must be considered, or maximum productivity over time at the lowest overall cost. Typically, EUR is projected over 10 years based on actual production rates taken at 30 days, 60 days and 90 days. The decline curve, representing the drop in production over time, is projected from these actuals, with low, best and high estimates to cover the range of uncertainty.

Much of the focus is, too often, on the well’s initial performance. Encouraged by time-to-production using familiar techniques such as water, producers might neglect to consider alternatives that could minimize the slope of the decline curve.

Adding CO₂ or N₂ to the fracturing treatment has been shown to optimize overall productivity (increasing EUR), even though the initial acquisition cost of these gases can be higher than nonenergized fluids such as slick or acid water. However, beyond their ability to improve fracturing itself, energized fluids significantly boost flowback and production performance through enhanced cleanup and minimal fluid retention. They also boost production significantly in depleted formations.

Uniquely positioned
As the industry continues to focus on reducing the amount of water required for hydraulic fracturing due to availability and disposal costs, greater emphasis is being placed on the use of cryogenic gases and associated field support services to achieve these goals. Agile industrial gas operators with extensive CO₂ networks across both the U.S. and internationally are well positioned to support even the largest fracturing jobs, such as Linde Gases’ CO₂ implementation in the Eagle Ford Shale in Texas, for which it had to call on its network of plants to execute a 4,000-ton project.

References available.