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

Model-based production analysis using analytical or numerical models is not a new phenomenon and is considered a robust technique for analyzing and forecasting production data; however, its application to unconventional reservoir systems often proves problematic due to model non-uniqueness resulting from long-term transient flow regimes. This non-uniqueness, an unavoidable fact when analyzing inverse problems, is worsened by the uncertainty surrounding input model parameters when attempting to describe reservoir systems with a great deal of complexity (e.g. very low permeability, geomechanical effects, near-critical fluids, natural fracturing, etc.). The problem facing the engineer presents itself when different combinations of input parameters yield nearly identical history matches but very different time-rate profiles and estimated ultimate recovery (EUR) values when forecasting future production for a particular well.A systematic framework that covers the full range of uncertainty for all relevant input parameters would clearly mitigate the ambiguity of production analysis and forecasting under uncertain conditions. In this work it is proposed that experimental design, which is a statistical technique used to describe or optimize a process by systematically analyzing the effect of the various controllable and uncontrollable factors of a system on an output (e.g. EUR), can provide such a framework. In this work, a methodology combining model-based production analysis with experimental design is used to history match and forecast fractured vertical and multi-fractured horizontal oil wells in the Vaca Muerta Shale with high-frequency time-rate-pressure data. The primary objectives of this work are to provide a comprehensive overview of the Vaca Muerta shale, outline experimental design as it relates to model-based production analysis, quantify uncertainties in model input parameters, and finally history match and forecast two wells that are producing in the Vaca Muerta Shale.

Production modeling is a process that requires analyzing several steps, from reservoir characterization, completion and hydraulic fracturing, up to the optimization in the production system. Traditionally these processes can be analyzed independently with separated specialized tools. However in unconventional reservoirs, as the Vaca Muerta shale, dependency between the stimulation treatment and the well productivity is critical. This work proposes a workflow to evaluate the joint impact of hydraulic fractures with the static and dynamic characterization of the reservoir.The available static information (geophysics, petrophysics, geomechanics and natural fracture interpretation) is integrated to build a geological model. Then, hydraulic fracturing is simulated numerically using the Unconventional Fracture Model (UFM). The model takes into account the interaction between the existing natural fractures and the created hydraulic fractures during the stimulation treatment. The resulting geometry of the hydraulic fractures is gridded in an unstructured manner. The model reproduces explicitly the volume and permeability with the appropriate distribution along each branch of hydraulic fractures according to the executed completion. Dynamic simulation can be run to perform a history match of the available production data. Hydraulic fracture geometry, driven by geomechanics and natural fractures, is a key component of the process and might be reviewed if no production match can be achieved making the overall workflow iterative. Additionally, automation through assisted history matching is proposed to investigate different possible solution and reduce the timeframe of the study.Once calibrated with production, the model allows several applications. The different possible solutions considered by the assisted history match process permit the evaluation of the uncertainty of final recovery when forecasting production. Sensitivity analysis over a given hydraulic fracture geometry shows the major role of the matrix saturation and conductivity degradation over the final recovery. Completion can be optimized by considering different scenarios and showing the direct correlation between generated propped surface and well productivity. Different fracture designs can be investigated to increase the propped surface highlighting the importance, not only of the proppant volume, but also of the proppant transport capability of the fracturing fluids to be used.

Proposal Before the start of an enhanced oil recovery project it is important to adequately describe the architecture of sand bodies, preferential flow directions and permeability barriers. As a consequence of project implementation operating costs tend to increase so in order to guarantee the economic success of the venture, reservoir surveillance plays a major role. This is mandatory in highly heterogeneous reservoirs where it becomes strictly necessary to identify and adjust any deviation from the anticipated response to injection. This paper presents the results of the use of chemical and radioactive tracers in Grupo Neuquen reservoir, Loma Alta Sur field, Argentina. The objectives have been to improve the dynamic description of the reservoir previous to the injection of costly polymers and surfactants and to optimise the secondary flood by increasing volumetric sweep efficiency. This field has been in production since 1990. Water injection started in 1993 and due to field observations of poor reservoir connectivity an intensive programme of tracers was recommended. Three injectors were inoculated, one of them with ammonium thiocyanate and the rest with tritiated water. Fifteen producers were monitored throughout twelve months. Field data is presented in this report. It shows that hydraulic connectivity is higher than expected although fluid migration among wells is highly variable depending on reservoir transmissibility and channel orientation. For wells separated only 300 feet arrival times of few hours were reported. From these observations it was concluded that many sand bodies still produce under primary recovery. Sands with better transmissibility and continuity are constantly recycling injected water contributing little to reduce oil saturation. As a consequence a full field reservoir description in a sand by sand basis was initiated before the implementation of an EOR process. Introduction Loma Alta Sur field is located in the south of Mendoza province, Argentina (Fig.1) in what is known as the folded belt of Malargüe. Enhanced oil recovery is being considered as an alternative to increase the final recovery factor of the field. Rock permeability curves combined with high oil viscosity, typically higher than 150 cp, produce a very unfavorable mobility ratio of 17. The use of polymers and surfactants in conjunction with hot water injection has been the choice in order to improve volumetric and microscopic sweep efficiencies. Loma Alta Sur field Discovered in 1990 it is now on a mature stage of development. After three years of primary production a peripheral waterflood pilot was devised with two injectors and six producers which was extended to the whole field between 1994 and 1995. In 1997 two infill wells were drilled with the objective of injecting hot water to reduce oil viscosity. However upon completion, productivities were so high that they have never been converted to injectors and today are still producing. Formation pressures taken during logging indicated that while some sands had responded to water injection, others were still at initial reservoir conditions. A complete lack of vertical communication was then inferred. Since then in all the infill wells that have been drilled, pressures were measured in a sand by sand basis to monitor waterflooding. Loma Alta Sur has been divided in four stratigraphic sequences labeled from bottom to top, V, VI, VII and GNS. The latter is not productive. Besides each of these sequences has a lot of sand bodies evidenced by the gamma ray and SP logs (Fig.2) In general the vertical pressures profiles indicated that only sequence V had responded to water injection, while sequences VI and VII were producing under primary recovery (Fig.3) This would be because sand bodies from the upper producing sequences would have less lateral continuity. The thickness and width of fluvial channels are related to each other in such a way that in accordance with the thickness of the sands present in this field they would not extend aerially more than 200 m. This was the main reason why the average well spacing was reduced from its original 260m to 205m and then to 170m, evidencing an increase in recovery factor (Fig.4). Actual distances for the pilot tracer program are in the order of only 120m.

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