State-of-the-art Multistage Fracturing to Help Achieve Branch Fracturing a report by
Loyd East, Mohamed Soliman, Jody Augustine and Milorad Stanojcic Halliburton
Horizontal drilling and multiple-fracture completions are the most common techniques used to extract these hydrocarbons economically. Thousands of wells have been completed in shale reservoirs in the US and Canada, including the Fort Worth Basin, the Arkoma Basin, the Appalachian Basin, Big Horn, Wind River and Powder River.
Hydraulic fracturing in shale reservoirs has evolved substantially to the point where unique fracturing treatment methods have been developed and are commonly referred to as unconventional reservoir solutions. These reservoirs are often characterised as nano-Darcy permeability, with micro-porosity, natural fractures and thin laminations containing free and adsorbed methane.1
Heterogeneous reservoirs usually have natural fractures or planes of weakness that may or may not be conductive under original state conditions. As a hydraulic fracture is created, the natural fractures may become dilated. As a result, when fracturing these reservoirs, the created fractures represent fracture networks as opposed to conventional thinking of bi-wing fractures. In very-low-permeability reservoirs, these network/branching effects result in greater connectivity to the reservoirs, allowing more pathways to produce hydrocarbon. This explains why nano-Darcy Barnett shale reservoirs are strategic economic assets to many operators.
The variety of fracturing methods used to effectively stimulate production has a key focus on creating far-field fracture complexity to generate ‘branch fracturing’. Branch fractures, also referred to as fracture networks, are desirable in nano-Darcy rock (
New processes have been designed for high pumping rates with low proppant concentration and multistage fracturing treatments. These involve pumping erosive gelled proppant slugs containing ultra-high sand concentration through the coiled tubing during the fracture treatment, and non-abrasive clean fluid in the annulus, saving the permanent tubulars from erosion. As a result, the rate down the annulus can be much higher. Pumping rate can be manipulated to customise the placement and concentration of proppant being pumped into the reservoir. In cases of premature screen-out, a well could be easily reverse-circulated and cleaned for the next stage. Proppant plugs eliminate a need for over-flushing, and the new approach to fracture stimulation – known as branch fracturing – can be achieved by changing proppant concentration in realtime.
Coiled-tubing fracturing has evolved substantially in recent years – from straddle-packer isolation, where all treatment fluid is mixed and pumped at a low rate through the coil, to a process that uses hydra- jet perforating service followed by annular path (HPAP) pumping of
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the treatment fluid at much higher rates than can be achieved by pumping through the coil tubing only.5,6
The use of coiled tubing in
the HPAP process provides solutions to many of the problems previously described in conventional high-rate water-frac technology:
• having coiled tubing in the casing during treatment provides a quick contingency for premature screen-out, allowing for more aggressive treatment designs;
•
hydra-jet perforating conducted by pumping through the coiled tubing does away with the need for separate trips into the wellbore, which reduces non-productive time in the well completion process and ensures that all intervals are adequately stimulated;
• •
seamlessly integrated processes can be conducted in 24-hour operations to add another level of efficiency to the completion process; and
the use of proppant slugs to create proppant packs at the end of each fracture treatment ensures maximum near-wellbore conductivity while providing a means to divert fluid to fracture treatments conducted further up hole.
However, there are two main drawbacks to the HPAP process when considering it for high-rate water-frac treatments. Abrasive fluid pumped down the annulus is typically limited to 35ft/second to prevent erosion of the coiled tubing, which limits the injection rates for most completions in unconventional reservoirs. Changes in treatment fluid properties, such as proppant concentration and stage volumes, are not realised in the fracture until the annular volume has been displaced.
Alternative Approach 1 – ‘Commuter Frac’ Stress Diversion Method
When considering the conventional water-frac design limitations, an alternative method is proposed to improve design control in realtime operations. Current limitations addressed are as follows: lack of deep penetration of proppant-laden fluid; inconsistent or risky diversion inside the fracture to create branch fractures; lack of ‘on-demand’ control of proppant schedules at the fracture entry point; non-productive time associated with the need to isolate previous frac treatments and perforating casing for new interval fracture treatments during multiple-interval fracturing operations requiring separate trips between stages; requirements for over-flushing perforations; risk of premature screen-outs in complex fracture networks; costly mitigation of premature screen-outs; erosion of surface and downhole equipment when pumping proppant-laden fluids at high rates; and realtime micro-seismic fracture mapping not integrated with the fracturing process to enable ‘on-the-fly’ control of created fracture geometry.
The Commuter Frac Process
The commuter frac is analogous to rush-hour traffic in large metropolitan cities. When wide thoroughfares are restricted due to construction, stalled
© TOUCH BRIEFINGS 2010
Natural Gas
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