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Oil production from the unconventional Vaca Muerta play is increasing as a result of a rigorous appraisal and exploitation strategy. Multiple wells have already demonstrated the potential of the Neuquén Basin, however optimization is still ongoing to determine the best practice for completing wells. A stand out difference of the Vaca Muerta play is its thickness (100 m to 450 m), as such a development strategy based solely on vertical wells is being considered in addition to the horizontal well strategy more commonly applied in other shale plays. The thickness of the Vaca Muerta formation creates new challenges and opportunities due to the stratigraphic variation in petrophysical and mechanical properties which can affect fracture effectiveness and well productivity. Completion design, geology and production performance need to be linked. Specifically, the geology of the Vaca Muerta formation, as is the case in most reservoirs, varies significantly more in the vertical direction in comparison to the horizontal direction. With optimum solutions not necessarily being intuitive, numerical simulation is critical as it enables a large number of variables to be analyzed and their individual impact understood and quantified. The objective of this paper is to present the four different approaches that have been used to build numerical models to represent the vertical wells in Vaca Muerta. These are: A single layer model with a planar fracture placed in a zone of improved permeability to represent the Stimulated Rock Volume (SRV) which is then surrounded by undisturbed matrix.A multilayer model with multiple planar fractures placed in an undisturbed matrix.A multilayer model with multiple planar fractures (one per stage), the SRV surrounding the fractures and the undisturbed matrix behind it.A multilayer model, where the SRV is modeled within a dual porosity model. This work shows how these models were constructed, the measurements that were honored and the estimation and justification of values assumed for unknown parameters. The impact of the different methodologies on the time taken and quality of the history match obtained and subsequent forecasts is also discussed. YPF has collected an extensive data set including PLTs, microseismic surveys, downhole pressure gauges, and pressure build ups, which has been used to constrain the numerical models. Building and history matching these models has been challenging but enables conclusions to be made about rock, fluid and completion interaction that cannot be obtained otherwise. The simpler models, have in some cases, enabled rapid estimates to be made for EUR which have subsequently been supported by the results from the more detailed modeling approaches.

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A 3D integrated saturation model was built for the Sierras Blancas Formation of the Neuquén Basin, Argentina. The saturation model was based on core, logs and seismic data. History match of reservoir pressure and well productivities were taken into account to accurately determine the gas in place and productive reservoir boundaries, specifically using 3D seismic water saturation in the gas condensate formation. The Sierras Blancas Formation is an eolian deposit. In tight, wet and diagenetically altered regions, the seismic inversion porosity and acoustic impedance based models were not adequate to describe the gas in place distribution. Further, the effective gas permeabilities in the tighter part of the reservoir are a strong function of the initial water saturation as evidenced by fewer condensate and water blocking problems of horizontal wells that navigated through low water saturation, high permeability regions. Any relationship between seismic impedance and porosity correlation degraded in areas affected by secondary diagenetic processes therefore necessitating the use of a saturation parameter. 30 vertical wells that had DT curves were selected based on their production and spatial location in order to establish a correlation between log saturation and seismic attributes. Seismic saturation cubes were generated by multiattribute seismic analysis and resampled into the simulation scale model. Log saturations were then co-kriged with the 3D seismic saturation. Water saturations obtained from the initialized simulation scale model were compared with the 2D saturation logs, the 3D seismic and the geological model scales. An objective function was defined to match the 3D seismic water saturation with the initialized simulation model water saturation. Model parameters were iterated until a satisfactory match with the initialized simulation model was obtained. By focusing the saturation match at the initialization stage, seismic, geological, petrophysical and SCAL models were ensured to be consistent prior to the full history match. Well history matching was consequently achieved much more simply and quickly. This paper presents a new detailed methodology of 3D pseudo-seismic water saturation generation, modeling and simulation used to accurately define OGIP, the productive boundaries of the reservoir, and to design trajectories for new horizontal wells.

In the Neuquen basin, center west of Argentina, a tight gas field was developed in submarine volcanic rocks. The field called Cupen Mahuida is a faulted anticline, which produced oil and gas from the upper formations. This deeper reservoir was discovered in 2001. The average depth is 3500 m and there are 16 wells producing from these rocks. The production is dry gas with a low CO2 content. Because the low permeability hydraulic fractures are needed to produce the wells and the productivity of them is highly variable. The pressure behavior during the fracture pumping showed the presence of natural fractures. These highly variable results in the wells pushed to get a more predictable reservoir model, and then 99 m of cores, 58 sidewall cores and 8500 m of cuttings were described in detail. Based on the information obtained the geological model was adjusted. Was found that these rocks were originated in volcanic eruptions both sub aereal and submarine and the eruptive products were deposited in a water body. There were several volcanoes feeding the area and were located about 20 km away from the deposits, and then the deposits have a distal position from the volcanoes. A probable volcanic center in the NE of the field was identified. Only one event has had sub areal exposition and could be use as a local correlation level. Micro fractures due to cooling, gas escapes, etc that are common in this kind of rocks when they are deposited sub aerealy are not present. The primary porosity was completely occluded and the current porosity is due to mineral dissolution. Open natural fractures are present but the density is low as well as the fracture width, some tectonic micro fractures were identified. Conclusions:The detailed rock analysis allowed to define the depositional environment, this knowledge changed the approach to analyze the porosity distribution. There are micro fractures, although this is not the largest source of porosity, primary porosity was destroyed because the rock alteration, the main porosity source came from the mineral dissolution.