The San Jorge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate undesired effects such as uncontrollable height growth, significant proppant pack damage, lengthy clean up times and high friction pressures. In recent times, polymer-free viscoelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Nevertheless, VES were known up to now, for their limitation to withstand elevated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given conditions of this high temperature formation. Since the reservoir temperature exceeded the technical limits of even this HT fluid, simulations indicated that a series of cool-down brine stages would allow the application of this fluid at this temperature (280F). The characteristic of the fluid allowed the treatment to be confined in the limited layer thickness between weak barriers avoiding growth into water - or non - productive zones, resulting in reduced fluid and proppant volumes. Field implementation proved also to be successful in terms of operational simplicity, reduced clean up time and consequently work over rig cost savings. Overall, the use of polymer-free fluids improved well productivity. Design, laboratory studies, temperature simulations confirmed by downhole measurements, field implementation and results of the first VES HT fluid application in the El Tordillo field are presented in this paper. Four different zones were successfully treated in the first well application at various reservoir conditions presenting a wide range of permeability and temperatures. Introduction The oil producing sands of the San Jorge Basin store important hydrocarbon reserves, covering an extensive area across South Argentina. The basin-fill was by fluvial deposition during the Cretaceous period. Wells are typically vertical and penetrate several thin laminated layers, of thickness ranging between one to eight meters. (Figs. 1 and 2) Furthermore, imprecise clay volume determination, uncertainty in the lithology, rock texture, structure and formation damage, are all aspects that represent a major challange in managing reservoirs in the San Jorge Gulf Basin. To make matters worse, the low well productivity offers operators only a marginal return on their investments. In an effort to increase productivity, the hydraulic fracturing technique has been adopted since many years, being in most cases the only method of achieving commercial production levels. A typical San Jorge Gulf Basin well has an interval of interest located between 800 to 1200 meters, with dozens of sand beds ranging from one to four, five or eight meters thick, many of them strongly laminated 1. This productive intervals were formed during the Cretaceous period, and is of continental origin, covering several formations whose names depend on the geographical area (see Fig. 2). The lithology changes from nine sands at the bottom of the well to twelve sands at the top of the productive interval. Many of these sand beds contain hydrocarbons but produce oil, water or gas, depending on the fluid saturations, relative permeabilities, rock and fluid characteristics. Presently fluid prediction success rate varies between 65% and 80%.

Latin America hasn't escaped the general industry trend of finding reserves in ever challenging environments. Complex geology and low permeability are the common denominator in today's environment. Developing reserves under these conditions with conventional vertical wells is in most cases uneconomical. In this setting, horizontal wells have come to mitigate the problem, however in most unfavorable conditions where oil and gas are found in tight formations fracture stimulation needs to be added to the equation. Conventional multistage fracturing techniques including perforating, fracture stimulating and isolating stages with a composite bridge plug have been applied in some cases with limited success. The time consumed in the completion operations extends over weeks making wells uneconomical. In addition, the prolonged time over which the frac fluid remains in the formation before being flowed back often affects well productivity. This paper describes the experience of three operators in Latin America that have implemented a new completion system to overcome the time consuming and productivity limitations of conventional completions described above. The new completion system is run as part of the production liner, does not require cementing and provides positive mechanical diversion at specified intervals, so fracturing and stimulations can be pumped effectively to their targeted zone. The system has also been designed, so all of the fracturing or stimulation treatments along the horizontal wellbore can be pumped in one continuous operation, thus minimizing the associated risks and optimizing the efficiencies of both the personnel and equipment needed to perform the work. The conclusions will show the operational efficiencies and reliability of this novel completion system, as well as analyze the cost benefits and production increases that have been observed. Introduction Operating companies are continuously pushing to improve hydrocarbon recovery, a task that is becoming more and more difficult as they are pushed to develop fields in more complex settings and with poorer reservoirs properties. Horizontal wells have been a tool widely used to improve both production rates and recovered reserves per wellbore in order to improve the economics of particular projects or make them commercially viable in extreme cases. Over the last two decades many developments have enabled accelerated growth in horizontal well applications. Drilling has led the way, with current technology capable of drilling thousands of feet laterally through a hydrocarbon reservoir. Drilling technology has evolved to a point where horizontal wells can be constructed at comparable costs to vertical wells while offering the advantage of higher production rates and better access to reserves. Often times fewer horizontals are required to develop a field given its larger drainage area. However horizontal well completion has lagged behind, in particular when a stimulation treatment is part of the completion or has to be applied as a remedial treatment in wells performing below expectations1.

In the Vaca Muerta shale of the Neuquén basin, Argentina, the most prolific intervals tend to be the most difficult to hydraulically fracture because of the abnormally high fracture gradients present in some parts of the basin. Thus, it becomes very important to have a good understanding of the anisotropic geomechanical properties of this heterogeneous formation prior to developing the completion strategy. A calibrated, anisotropic 1D mechanical earth model (1D MEM) was developed and used to optimize the completion strategy for a vertical well in the Vaca Muerta shale. The output from the 1D MEM, including the principal stresses, anisotropic elastic properties, pore pressure, and rock strength, were used to define the reservoir intervals with the best characteristics for initiation, propagation, and maintenance of a conductive complex fracture network. Next, the reservoir intervals with the highest hydrocarbon generation tendency were determined from petrophysical and image logs acquired in the well. This formed the basis for selecting the optimum number of stages and perforation strategy for the well. Sensitivity analysis revealed the impact of the hydraulic fracture properties on the production performance. The analysis showed that higher fracture conductivity greatly improves the well performance in the deeper Vaca Muerta intervals, whereas larger fracture surface area is more beneficial across the shallower intervals. Thus, a unique completion strategy was developed for each interval to optimize the well performance. Three hydraulic fracture stages were planned initially, but because of casing limitation, only the first stage was executed. A time-lapse acoustic measurement acquired from the well corroborated the propped fracture height predicted during the completion design phase. The study showed that proper characterization of the anisotropic geomechanical behavior of the Vaca Muerta formation improves the development of a completion strategy, which ultimately optimizes economic performance of the well.

This paper presents an operator's approach to optimize future well performance by fully integrating all the data captured in the Vaca Muerta shale. Based upon insight from the study, the operator needed to make more informed asset management decisions, understand the interaction between the shale and the hydraulic fracture network, and improve economics. Data were captured from several wells, both vertical and horizontal. The data incorporated into the study included fieldwide seismic data, as well as mineralogical, geomechanical, well plan, drilling, completion, microseismic monitoring, and production data from the wells.The project comprised one case history involving the hydraulic fracture stimulation treatment of a cluster of horizontal wells. Microseismic hydraulic fracture monitoring (HFM) was utilized to "track" the development of the hydraulic fractures in real time as they propagated throughout the formation. The stimulation activity from the well was monitored from a horizontal array placed in a horizontal lateral drilled parallel to the target well but landed~80 m shallower in the vertical section.An integrated unconventional-reservoir-specific workflow was utilized to develop and evaluate the completion strategies for the subject well. First, a fieldwide 3D static geologic model was constructed using the aforementioned data to determine the best reservoir and completion qualities of the Vaca Muerta formation. Next, the model was used to develop the completion strategy, including staging, perforation scheme, stimulation design, etc., for the wells. The completion strategy and stimulation design were performed utilizing an automated, rigorous, and efficient multistaging algorithm (completion advisor). This enabled targeting the reservoir section having the best reservoir and completion qualities for the stimulation treatments. The stimulation designs were performed using a state-of-the-art unconventional hydraulic fracture simulator that properly simulates the complex fracture propagation in shale reservoirs, including the explicit interaction of the hydraulic fractures to the pre-existing natural fissures in the formation and performs automatic gridding of the created complex fractures to rigorously model the production response from the tridimensional fracture network.A comparison between the microseismic fracture geometry to the planned fracture geometry is revealing; it shows that the application of this new technology can identify some of the complications and

The channel hydraulic fracturing technique was recently introduced to the oil and gas industry as an alternative to the conventional hydraulic fracturing methodology. Channel fracturing involves the creation of a network of open channels or flow paths within the stimulated fracture volume, enabling the increased flow of hydrocarbons through the channels and into the wellbore. This paper investigates the applicability of this novel technique in the Vaca Muerta shale and presents a case history evaluating the potential production benefits of this methodology.Starting with a calibrated geomechanical model, an index profile was created using the ratio between the young's modulus and closure stress to determine if channel fracturing is applicable in the Vaca Muerta. The technique is compared to conventional hydraulic fracturing case to identify the differences in the created fracture properties. Based on the created channel fracturing index profile, the gross Vaca Muerta shale interval was divided into three intervals (lower, middle, and upper) and the process was repeated across each section to determine the incremental production impact across interval.The result of this study shows that the channel fracturing technique is applicably in the Vaca Muerta shale and can potentially increase the production performance. The analysis also shows that this technique is more favorable primarily across the upper and middle Vaca Muerta intervals than the lower Vaca Muerta interval due to the high organics, low rock moduli, and high stress. Also, permeability degradation of the proppant pack does not negatively impact the overall conductivity in a Channel fracture system. Instead, loss of aperture reduces the conductivity by orders of magnitude.