The primary goal of a hydraulic fracturing treatment is to create a highly conductive flow path to the wellbore that economically increases well production. In moderate and high permeability wells the lack of adequate fracture conductivity is a limiting factor in the production potential of the well, whereas in tight gas reservoirs the limiting factor is often the effective fracture half-length. Even in the last case, adequate fracture conductivity is important to allow efficient recovery of the fracturing fluid. Traditionally, efforts to enhance conductivity have been directed to improve the ability to flow through a porous proppant pack. The industry has extended significant efforts towards the goal of increasing proppant pack permeability through the development of less damaging carrier fluids, higher strength man-made proppants, more efficient fracturing fluid breakers and so on. As an industry however, we continue to struggle with the fact that well testing frequently indicates disappointingly shorter or less conductive fractures than designed. Multiple studies indicate that proppant-pack retained permeability is often a small fraction of the maximum expected value. This manuscript describes a novel hydraulic fracturing technique that enables a step-change approach towards increasing fracture conductivity. The technique is based on the creation of a network of open channels inside the fracture. Modeling and experimental work indicates that the new technique can deliver conductivities in excess of ten-times those obtained from conventional fracture treatments. Extensive lab-, yard- and field- scale experiments combined with theoretical work allowed creating the framework that describes the physical processes occurring during the application of this new technique. By providing significantly higher fracture conductivity, this new fracturing approach delivers a number of consequential benefits: better fracture cleanup; lower pressure loss within the fracture; longer effective fracture half-lengths, all of which will contribute to improved short- and long-term production. A 15-well field study, selected from over fifty treatments performed up to date with this technique, is presented to show posttreatment results with significant gains in well production and expected ultimate recovery with respect to offset wells treated with conventional fracturing methods.

Gas production from the unconventional Barnett Shale reservoir now exceeds 3 Bcf/d, which is more than 5% of total U.S. dry gas production. Typically Barnett Shale wells exhibit a rapid production decline following the initial hydraulic fracture stimulation treatment, so that, within 5 years, an operator is normally faced with a well producing below its economic threshold. To keep up with current gas demand, operators have moved to an aggressive horizontal drilling and completion program. Additionally, in an effort to increase the productivity of existing wells and book additional reserves at reduced cost, operators have restimulated their older vertical wells, with demonstrable success. This success is providing compelling opportunities to enhance refracture treatment coverage by targeting bypassed and ineffectively stimulated zones in additional vertical wells and even some horizontal wells. Because of the heterogeneous nature of this unconventional gas reservoir, the restimulation of horizontal wells is problematic, and operators have demonstrated limited success using current stimulation techniques. This paper describes a new fracture diversion technique particularly adapted for horizontal well refracture stimulation. During the treatment, a fracture diversion system (FDS) is used to create a temporary bridge within the active fracture networks. That results in differential pressure increase and causes treatment redirection to understimulated intervals along the lateral. This technique enables both fracture diversion without mechanical intervention and, when enhanced with microseismic monitoring, real-time optimization of the fracturing treatment. Refracture stimulation case studies are presented in which this novel diversion technique is successfully applied to horizontal Barnett Shale wells. This paper demonstrates how real-time hydraulic fracture monitoring has enabled operators to make informed decisions that influence fracture geometry, increase lateral coverage, and improve gas recovery. To date, more than 20 fracture diversion designs have been successfully placed. The trial wells have included both cemented and uncemented completions, with drilled azimuths selected to encourage either transverse or longitudinal fracture fairway development. With a continuing optimization of the described refracturing technique, these FDS designs and placement strategies have evolved to the point where they are consistently exhibiting fracture diversion as evidenced by movement of microseismic activity and improved lateral coverage. While this engineered fracture diversion technique is ideally suited for re-fracture stimulations, it is also applicable for stimulation of new wells where the technique enables stimulation of larger wellbore intervals when used in the same fashion as for re-fracture stimulation applications. Introduction The Barnett Shale is a Mississippian-age marine shelf deposit that unconformably lies on the Ordovician-age Viola Limestone/Ellenberger group and is conformably overlain by the Pennsylvanian-age Marble Falls Limestone (Ketter et al. 2006). Formation thickness varies from 200 to 800 ft through the reservoir. The productive rock is typically a black, organic-rich shale with ultralow permeability in the range of 70 to 500 nanodarcy. To attain economically viable production rates, hydraulic fracture stimulation is a necessity.

A new technique for characterizing secondary and tertiary reactions during sandstone matrix stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent element concentrations, batch reactor experiments and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long core flow tests and laboratory radial flow setups, are reviewed. The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%. Introduction Recent studies on matrix stimulation have strongly emphasized the importance of secondary and tertiary reactions in determining the success of matrix stimulation treatments.1,2 However, the extent of these reactions under reservoir conditions is difficult to quantify. Several factors make the traditional acid response tests on short reservoir cores inadequate for characterizing secondary and tertiary reactions. First, secondary and tertiary reactions are slower than primary reactions, and so much longer fluid residence times in the core are required to observe these reactions. Second, linear flow along the axis in cylindrical cores is not representative of radial flow in a reservoir treatment. Third, cores used in the core tests may not be representative of the entire treatment interval. Fig. 1 illustrates the limitations of traditional core flow tests. Fig. 1a shows that a core plug is a small sample of the area of interest. For formations in which the mineralogy changes significantly in the pay zone interval, a single core plug will not be representative of the entire treatment interval. Fig. 1b shows an example of how a traditional core flow test to evaluate two fluids on a short reservoir core can lead to erroneous conclusions. Shown in the figure are permeability profiles in a simulated reservoir treatment after injection of 50 gal/ft of acetic acid preflush followed by 100 gal/ft each of (i) 12/3 mud acid and (ii) an organic fluoboric acid. In both cases the reservoir was undamaged prior to treatment. 12/3 mud acid provides good stimulation near the wellbore, but causes damage deeper in the reservoir. The organic fluoboric acid achieves a lesser stimulation near the wellbore but also causes lesser damage deeper in the reservoir than 12/3 mud acid. The post-treatment skin for the organic fluoboric acid is –0.5, compared to a skin of 2 for the 12/3 mud acid. The organic fluoboric acid is, therefore, a better fluid for the reservoir treatment. However, if these two fluids were evaluated with a traditional core flow test, 12/3 mud acid would have been erroneously selected because it provides better stimulation at the length scale of the core (~4 in.). Therefore, core tests on short cores by themselves are inadequate for fluid selection for matrix treatments. For accurate evaluation of a proposed stimulation design, it is necessary to account for the formation damage caused by secondary and tertiary reactions, which are typically not observed in tests on short cores. Literature Review The following is a brief review of the techniques suggested in the literature to quantify secondary and tertiary reactions and to overcome limitations of tests on short cores.

Summary A new technique for characterizing secondary and tertiary reactions during sandstone-matrix-stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent-element concentrations, batch-reactor experiments, and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long-core flow tests and laboratory radial-flow setups, are reviewed. The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix-treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%. Introduction Recent studies on matrix stimulation have strongly emphasized the importance of secondary and tertiary reactions in determining the success of matrix-stimulation treatments.1,2 However, the extent of these reactions under reservoir conditions is difficult to quantify. Several factors make the traditional acid response tests on short reservoir cores inadequate for characterizing secondary and tertiary reactions. First, secondary and tertiary reactions are slower than primary reactions, and so, much longer fluid-residence times in the core are required to observe these reactions. Second, linear flow along the axis in cylindrical cores is not representative of radial flow in a reservoir treatment. Third, cores used in the core tests may not be representative of the entire treatment interval. Fig. 1 illustrates the limitations of traditional core flow tests. Fig. 1a shows that a core plug is a small sample of the area of interest. For formations in which the mineralogy changes significantly in the pay-zone interval, a single core plug will not be representative of the entire treatment interval. Fig. 1b shows an example of how a traditional core flow test to evaluate two fluids on a short reservoir core can lead to erroneous conclusions. Shown in the figure are permeability profiles in a simulated reservoir treatment after injection of 50 gal/ft of acetic acid preflush, followed by 100 gal/ft each of 12/3 mud acid (12 wt% hydrochloric acid (HCl)/3 wt% hydrofluoric acid (HF) and an organic fluoroboric acid (i.e., a mixture of citric, boric, and hydrofluoric acids). In both cases, the reservoir was undamaged before the treatment. 12/3 mud acid provides good stimulation near the wellbore but causes damage deeper in the reservoir. The organic fluoroboric acid achieves a lesser stimulation near the wellbore but also causes less damage deeper in the reservoir than 12/3 mud acid. The post-treatment skin for the organic fluoroboric acid is -0.5, compared to a skin of 2 for the 12/3 mud acid. The organic fluoroboric acid is, therefore, a better fluid for the reservoir treatment. However, if these two fluids were evaluated with a traditional core flow test, 12/3 mud acid would have been erroneously selected because it provides better stimulation at the length scale of the core (˜ 4 in.). Therefore, core tests on short cores by themselves are inadequate for fluid selection for matrix treatments. For accurate evaluation of a proposed stimulation design, it is necessary to account for the formation damage caused by secondary and tertiary reactions, which are typically not observed in tests on short cores.

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