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%.

fax 01-972-952-9435. AbstractThe 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 wateror 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.