Gas injection for shale gas recovery
Injection of CO2 or N2 is a more effective approach than conventional water and sand fracturing to increase oil and gas production from tight or water sensitive formations.
ROBIN WATTS and KEVIN WATTS
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Shale gas and other hydrocarbons, trapped within massive formations, have become an important source of natural gas and oil in the US 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 1% of total US natural gas production, but by 2010 shale gas accounted for over 20% and the EIA predicts that, by 2035, 46% of the US’s 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, France, Austria, Poland, Ukraine, Saudi Arabia, Russia and China representing large estimated unconventional resources.
Today, low permeability source rock (including shale gas, tight sand gas, and coal seam gas) is made economically productive in wells drilled and hydraulically fractured (propagating fractures in the hydrocarbon-trapped rock layers). This fracturing is done by pumping fluids carrying proppant including sand, sintered bauxite and similar materials, and pressurising the formation until it fractures. The fractures will continue to propagate, typically horizontally, away from the wellbore until the pumping pressure decreases below the fracturing pressure of the formation. The proppant serves to hold the fractured pathways open, creating what is termed ‘conductivity’ for the release of liquid hydrocarbons or natural gas.
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 ultimate goal of well stimulation is to economically achieve maximum productivity at the lowest unit cost. However, achieving economically desirable fracture penetration and conductivity can be particularly challenging in unconventional reservoirs.
While hydraulic fracturing and horizontal drilling have forever changed the natural gas industry by enabling exploitation of reservoirs that were previously inaccessible, the most common form of this 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. Additionally, the water can cause clays to swell in the formation, thereby blocking pore throats, reducing permeability and embedding proppant. This fluid which remains in the formation lowers the fracture conductivity, reducing or impeding the flow of oil and gas.
Very often in water based hydraulic fracturing fluids, the majority of the water is never recovered from unconventional reservoirs and the water that is recovered is contaminated. Gelled fracturing fluids must be flushed from the formation to clean out as much residue as possible from the proppant pack and may result in significant fines from over-flushing. 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, creating the required extraction fluid formulation involves significant aqueous chemistry costs and is associated with the use of massive amounts of water, whereby a single stage or reservoir interval can require the equivalent of two or more Olympic size swimming pools of water being pumped down the hole into the reservoir.
But water life cycle costs have risen significantly. This is especially true in areas now experiencing water shortages and droughts, as well as those areas 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 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 sometimes make better, in this case it does not result in optimal wells.
The use of nitrogen and carbon dioxide (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 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. N2 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 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 treatments energised with CO2 or N2 are increasingly being recognised for maximising long term well productivity as a result of minimising environmental damage with a smaller well site footprint without the requirement for large water retention ponds. It also reduces the 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 reservoir friendly. Energised treatments place significantly less water into the reservoir. In addition water can take up â€¨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 (see Figure 1).
Energising the fracturing fluid with CO2 or N2 also improves the total flowback 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.
Energised solutions also offer the ability to have superior proppant transport properties and, in the case of under-pressured or depleted zones, provide enhanced energy for hydrocarbon recovery.
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