Klaas A.W. van Gijtenbeek

New Hydraulic Fracturing Process Enables Far-Field Diversion in Unconventional Reservoirs

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).

Overdisplacing Propped Fracture Treatments-Good Practice or Asking for Trouble?

One of the major issues that comes with the development of unconventional ultra-tight shale gas reservoirs is related to under-displacing or over-displacing hydraulic proppant fracture treatments in multiple zone completions in horizontal wells. Multi-stage hydraulic proppant fracture treatments in horizontal well completions in tight gas reservoirs are, in general, under-displaced to ensure that a highly conductive path exists between the reservoir and the wellbore. In recent years, a large amount of multi-stage propped fracture treatments in horizontal wells in ultra-tight shale gas reservoirs are being over-displaced in order to get a clean wellbore and avoid problems with the hardware used for rapid multi-zone completions. Clean-out treatments are not required and therefore multiple treatments can be performed quickly, saving time and money. This practice may result in a poor connection between the ultra-tight reservoir and the wellbore. On the other hand, if the rock strength is sufficient, over-displacing a treatment could result in a very high conductivity region at the wellbore. This mechanism is similar to what has been seen in some wells with proppant flowback, where well productivity has increased following proppant flowback, which creates channels in the proppant pack near the perforations. This paper discusses these practices and, based on a combination of finite element modeling and fine gridded reservoir simulation, will try to answer if and when over-displacing fracs in shale or tight gas reservoirs should have a positive or a negative effect on production.

One-Molar Salt Solutions Used for Clay Control in Water-Based Frac Fluids in Western Siberia (Russian)

The use of oil-based fluids in the western Siberian oil industry for hydraulic proppant-fracturing treatments in water-sensitive formations to prevent clay swelling was widespread. The added advantage of using oil-based fluids for cold weather conditions is obvious. However, with the growing number of treatments and increasing treatment sizes, the use of oil or diesel, from an economical point of view, becomes less attractive. In addition, there is a growing environmental concern with respect to using oil for mixing and pumping fracturing fluids. The use of gelled water is cheaper, and from an environmental perspective, more attractive. The addition of 2% KCl to water-based fracturing fluid for temporarily controlling clay swelling is widely accepted as a standard practice. In situations where water-sensitive sandstone formations have been treated and longer protection has been required, very often additional clay stabilizing agents are added to the water-based fracturing fluids. Research on the technology of matrix acidizing treatments has revealed that the use of 2% KCl transforms into 1.5% saltwater as a result of ion exchange. The 1.5% saltwater solution is too weak to prevent clay swelling. Clay swelling can be prevented using a 1 molar (7%) KCl salt solution. Based on acidizing treatment research, it was decided to use 7% KCl as a temporary clay control additive in waterbased fracturing fluids for treatments in western Siberia. Onemolar salt solutions have been used for all the treatments performed during the last four years. Model 50 viscometer measurements were made to identify the influence of increasing KCl concentration from 2% to 7% on the viscosity development of borate crosslinked fluid. Water retention problems have not been reported since 7% KCl has been used. From a study of the pre- and post-fracturing production data, it was apparent that in general the percentage of water produced with the oil did not reduce. It is postulated that this is an indication of good temporary clay control. This study excluded treatments that clearly contacted a water-bearing zone.