Multiple-zone stimulation poses unique challenges for completion engineers. Achieving accurate fracture and proppant placement while performing an efficient and low-risk operation can be unattainable when using conventional stimulation methods. The uncertainty with respect to fracture and proppant placement is amplified when fracturing in ductile rock, where, to maximize access to the reservoir, more fractures must be placed along a given lateral. This increase in fracture intensity can result in an increased risk of unplanned well intervention and downtime, with more trips to run guns, as well as more plugs to drill out.
Stimulation techniques involving coiled tubing (CT) deliver improved efficiencies in horizontal completions because of the ability to instantly address contingencies by having CT in the hole throughout the operation. This method enables accurate fracture and proppant placement, as these operations typically focus on placing one fracture at a time. Isolation is commonly achieved using sand plugs, which have demonstrated to be especially effective; however, when fracture intensity is applied, sand plugs might not achieve the spacing required. This is because of the length of sand plugs often necessary to achieve isolation. Also, the time to set sand plugs can be considerable if they do not properly set the first time.
This paper introduces a new CT annular fracturing (CTAF) system, referred to as CTAF-Anchor, that offers a low-risk, operationally efficient, and effective multizone stimulation method designed to reduce the non-productive time (NPT) between stages and allow for closer fracture spacing to maximize stimulated reservoir access. Also included is a detailed study of the process and case histories that translated into a maximized return on investment (ROI) for the operator.
The challenge in recovering hydrocarbons from shale rock is its very low permeability, which requires cost-effective fracturestimulation treatments to make production economic. Technological advances and improved operational efficiency have made production from shale resources around the globe far more viable; however, while the wells being completed today are proving to be reasonably economical, the question that remains is if the operators are truly capitalizing on their full potential. In recent years, the industry has been in search of a better method to enable well operators to capitalize on the natural fractures commonly found in shale reservoirs. If properly developed, these natural fractures will create a network of connectivity within the reservoir, potentially improving long-term production when they have been propagated. In most shales, however, the stress anisotropy present can prevent sufficient dilation of the natural fractures during stimulation treatments. To induce branch fracturing, far-field diversion must be achieved inside the fracture to overcome the stresses in the rock holding the natural fractures closed. Increasing net pressure during the treatment will enhance dilation of these natural fractures, creating a complex network of connectivity, and the greater the net pressure within the hydraulic fracture, the more fracture complexity created.
Most of the various processes introduced previously are limited because multiple perforated intervals or large open annular sections are treated at one time. Also, to achieve the high injection rates required, they are treated down the casing, so that any changes made to the treatment require an entire casing volume to be pumped before these changes reach the perforations. This paper presents a case history of a multistage-fracturing process that allows real-time changes to be made downhole in response to observed treating pressure. This functionality enables far-field reservoir diversion to be achieved, ultimately increasing stimulated reservoir contact (SRC).