The full potential

Robin Watts and Kevin Watts discuss energised solutions for fracturing: safe, reservoir-friendly and water-saving well stimulation

Shale gas and other hydrocarbons trapped within massive shale formations have become an important source of natural gasand oil in the United States since the start of the 21st century and interest has spread to potential gas shales across the rest of the world. Europe now stands at having an estimated 21 trillion cubic feet, as indicated in the latest environmental impact studies by the US Energy Information Administration (EIA). In 2000, shale gas resources provided less than one per cent of total US natural gas production, but by 2010 shale gas accounted for over 20 per cent and the EIA predicts that by 2035, 46 per cent of the United States’ natural gas supply will come from shale reservoirs. Some analysts expect that shale gas will come to play an expanding role in world energy supply with potential shale gas and shale oil reservoirs in India, Romania, Poland, Saudi Arabia and China, to name a few.

The combination of two existing technologies, horizontal drilling and hydraulic fracturing, has made it possible to tap into this hydrocarbon-resource, leading to a shale gas and oil revolution that is seeing thousands of horizontal wells drilled and completed annually.

The most common extraction process has used 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 – and 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 and 5 million gallons (and as high as 10 million gallons) – led some communities to require producers to disclose consumption figures.

Energised solutions for extraction
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 may sometime make better, in this case, it does not result in optimal wells.

The use of 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 even proppant. CO2 serving to displace water in hydraulic fracturing, continues to be a proven method used in well stimulation of reservoirs from Saudi Arabia to South Texas. Energising solutions, using CO2 or nitrogen 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, an alternative to CO2 for well stimulation, has also been proven effective for well stimulation of shallower reservoir environments. Nitrogen hydraulic fracturing formulations include using 100 per cent 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 gas and oil wells the so-called ‘energised solutions’ are able to enhance hydrocarbon production rates and yield improved long-term economic recovery over the life of the well. Fracturing treatmentsenergised with CO2 or N2 are increasingly being recognisedfor maximising long term well productivity as a result of minimising environmental damage with smaller wellsite footprint sans large water retention pond requirements. It also reduces overall costs of water transport, treatment and disposal. A well designed energised treatment can in fact be more economical than water while also being more reservoirfriendly. Energised treatments place significantly less water into the reservoir. In addition it can take up valuable time during flowback, causing increased time to well clean-up of the water pumped downhole.

Recent studies indicate that, from an economic perspective, hydraulic fracturing with solutions energised by CO2 or N2 can achieve significantly more hydrocarbon recovery than non-energised approaches. One such study1 found that use of energised fluids improved well performance by up to 2.1 times, compared with non-energised solutions.

Energising the fracturing fluid with CO2 or N2 also improves the total flowback water volume and rate, minimises fluid retention and reduces the required water volume, which can have significant economic implications. Critically, energising 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 energised solutions allows for 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 minimising the amount of aqueous fluids introduced to the formation.

To realise the full potential value of an oil field and to achieve the highest recovery factor, using energised 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 optimising recovery along with the costs of that production. Energised fluids offer the means to maximise the recovery factor and importantly, if planned from a field-wide perspective, the means to optimise the cost of production. To strive for the greatest Estimated Ultimate Recovery (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, 60 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.

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

Adding CO2 or N2 to the fracturing treatment has been shown to optimise overall productivity (increasing EUR), even though the initial acquisition cost of these gases can be higher than non-energised fluids such as slick or acid water. However, beyond their ability to improve fracturing itself, energised fluids significantly boost flowback and production performance through enhanced clean-up 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. Linde Gas, a division of The Linde Group, a global leader in the international industrial gases market, was the first company to supply CO2 directly to the wellhead for hydraulic fracturing. Linde is uniquely positioned to work on a worldwide scale with oil and gas producers and oilfield service companies for fracturing and enhanced oil recovery. Services include a complete fleet of CO2 transports, even to remote locations, and a strong N2 supply network.

1 3 Burke, L.H. and Nevison, G. W. 2011. Improved Hydraulic Fracture
Performance with Energized Fluids:
A Montney Example. Recovery-2011 CSPG CSEG CWLS Convention

Robin Watts is Oil & Gas Technology Manager with Linde’s Energy Solutions Group, and Kevin Watts is Director of EOR Business Development, The Linde Group. Linde is the largest industrial gases and engineering company globally with over 65,500 employees working in more than 100 countries. Industrial gases are an integral part of our everyday lives – they used for a multitude of applications in manufacturing and production across a wide range of industries including oil & gas and refining.

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