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.

Low-permeability formations must be hydraulically fractured to produce at commercial rates. A good understanding of the formation stress conditions is critical for completion design, but requires in-situ measurement as calibration to support the geomechanical evaluation. This calibration is commonly done using diagnostic formation injection test (DFIT) methodology by creating a hydraulic fracture and then waiting for it to close through leakoff to the formation. However, in a low-permeability low-leakoff environment, application of this approach might become limited because of the time to fracture closure and the non-uniqueness of the interpretation. This paper demonstrates the applicability of the fracture flowback method to define closure pressure. Although proposed in the 1980s, this method has been underused by the industry. One of the objectives of this paper is, therefore, to advocate through field examples its simplicity of development, interpretation, and repeatability, particularly in low-leakoff reservoirs such organic shale formations. The procedure is composed of a sequence of various cycles of pump-in flowback through a fixed choke, pressure rebound, and fracture reopening. The proposed methodology offers several minimum stress measurements for repeatability and quality check purposes, reduces interpretation non-uniqueness, and can be completed within 1 hour, making it compatible with the hydraulic fracturing operations. Test design considerations, such as well geometry, pump rate, fluid volume, choke size, or perforation requirements, are reviewed to maximize the chance of success. Interpretation of the different possible patterns that can be observed is discussed and illustrated with practical examples from the Vaca Muerta shale. Comparison is made between the pump-in flowback and calibration decline approaches performed over the same interval. Repeatability is evaluated, and discrepancies between cycles are investigated. A direct application of the method is the calibration of a stress profile when applied to a vertical well. However, additional observations related to the fracture closure mechanism or residual fracture conductivity can be drawn by detailing the flowed-back volumes or rate of rebound pressure. These observations can be related to the lithology when the procedure is implemented in different intervals of the same formation.

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The successful application of fracturing for sand control has been reported from many different areas. Several explanations have been advocated for these successes such as "re-stressing" the wellbore, creation of a "halo effect" around the wellbore and maintaining the bottom hole pressure above a critical level to prevent perforation collapse. The latter approach has led to complex models predicting the conditions of perforation failure. However, once the perforations have collapsed, the production of formation sand is governed by the transport of the sand from the perforation tunnels. Frequently, decreasing the production rate stops sand production, indicating that there is a critical flow rate below which sand cannot be transported into the wellbore. In this study, we present the development, application and field validation of a spreadsheet tool to improve the reliability of fracturing for sand control treatments. A universal curve was generated from numerical simulations, showing that the percentage of the total flow through the perforations not connected to the fracture was a function of the formation and fracture properties and was independent of the reservoir fluid properties. The generation of a universal curve eliminates the need to use a reservoir simulator and allowed the development of a tool to aid the design of fracturing for sand control treatments. The spreadsheet tool has been validated with data from successful fracturing for sand control treatments. Introduction Successful applications of fracturing for sand control have been reported in the literature1,2 as well as in the field. Several mechanisms have been proposed for these successes. Some have put forward the "re-stressing" of the wellbore3 via the addition of a foreign material: the proppant pack. Some have investigated the creation of a "halo effect" around the wellbore4. Others studied the elevation of the bottom hole pressure to prevent perforation collapse.5 The latter approach led to the development of complex models predicting the conditions of perforation failure.6,7,8 In cases where optimised perforating (0° phased or 180° phased oriented in the preferred fracture direction) has been followed by fracturing, the fracture covers all the perforations eliminating problems due to failed perforations.1 In most of the field cases reported in which fracturing for sand control has been used, sand production had already begun. In the reported cases, sand production may have come from perforation debris or failed perforation tunnels.9 The quantification reported has never been sufficiently accurate to distinguish between these two cases. Nor do we have enough information to assess whether the sand production regime was transient (sand bursts) or permanent.3 In both cases however, we can conclude that the flow rate in at least one perforation was sufficient to produce enough sand to require a remedial operation. The importance of fluid flow in the perforations has been recognised by Tronvoll et al.8 to describe the sand production pattern after perforation collapse. Interestingly enough, the flow rate at which sand production started is normally available from these wells. It is logical to interpret the flowrate at which sand production is detected as a critical flowrate below which no sand is being transported towards the wellbore - assuming that the flow rate is sufficient to lift the produced sand up the production tubing. In the present study, we analyse how fracturing affects the flow pattern in the near wellbore area, and how we can use fracturing alone as a sand control/sand management tool.

The declining reserves in conventional gas reservoirs imply that the oil and gas companies must consider the production of tight no-conventional gas reservoir. The Cupén Mahuida Field is a naturally fractured reservoir composed of series of volcanic and volcaniclastic layers developed into a synrift stage at the Triassic in the Neuquén Basin. To obtain economical production all interesting layers had to be fractured. Therefore, we can assimilate that field to a tight gas, no-conventional reservoir. Due to the huge difference in production between the different layers fractured in the existing wells, and due to the differences in behavior of the pressure during the treatments, it was decided to conduct a detailed analysis of each case. This included well construction, perforating strategy, geology, petrophysics, images log, minifracs and fracture treatments. The results of the study showed two directions of work: First, necessity to modify the operations schedule; second, we needed to improve the definition of what are the layers candidates to stimulation. So operationally, we decided to change the casing size, the perforation scheme and we included as normal practice the use of proppant slugs to reduce the tortuosity effects we may see. The selection of candidate was improved by a better understanding of the formation thru an evaluation of outcrops that permitted to characterize the volcano clastic events and to correlate them with images, nuclear magnetic resonance logs and pressure measurements. With that information and the pressure response in the minifrac analysis we define the optimum size of treatment and the final proppant concentration. Introduction This case study describes a multi disciplinary evaluation of fracture treatments in a naturally fractured volcanoclastic reservoir. It corresponds to the Precuyano formation in the Cupén Mahuida field situated at around 80 Km of Neuquén city, center of Argentina (fig. 1). All the evaluated wells are vertical. Fig. 1: Location Map The net pay is composed of several layers (3 to 7) of porous volcanic rock situated between 3100 and 3700 m and is overpresurized. The net pay height of each layer may vary between 5 and 30 m. Based on the first petrophysical interpretation it was considered that the net pay could be assimilated to a non-fractured clastic rock, and the stimulations were first designed on that basis. The first wells drilled were exploratory and completed with 7" casing. Now the development wells are completed with 5" casing. Those changes allowed to improve the perforation strategy and to reduce the fracture entry problems. An overview of the first results showed that the response of the reservoir was the one of a naturally fractured rock, and that we could not draw a direct relation between the production results of the individual layers and the log information as porosity, height and pressure. So, each individual fracture was evaluated and its production in time, looking at more detailed reservoir characteristics, as natural fractures density, rock deposition system, to be able to define what layers are best candidates and how to design the frac operation for the different type of candidates.