In low and tight gas formations, condensate banking will form in shortly time after production start-up due to pressure drop below the saturation pressure. Mobility reduction near wellbore area will affect well productivity. The prediction of gas condensate wells production will strongly depend on oil banking evaluation and modeling. A benchmark radial fine well model has been built using constant petrophysical properties per each layer. Several coarse Cartesian grids have been considered to evaluate discrepancies in terms of production and flowing pressure with respect to the benchmark grid. For a coarser Cartesian grid, it has been deduced that Generalized Pseudo-Pressure (GPP) is a key parameter to avoid well performance over-estimation. An alternative solution consists in defining a local grid refinement (LGR) near wellbore to honour the benchmark solution without using GPP. In this case study a LGR technique has been used to incorporate future hydraulic fractures for the wells development. A real application case has been considered to extend lessons learned from benchmark to field scale. A proper geological model has been built using a sedimentological model as driver for petrophysical properties distribution. Two DST have been considered to analyze condensate banking phenomena evaluation in a low and medium permeability matrix. To this purpose, three analytical models have been considered. Thus, to validate a representative analytical model a numeric simulation has been performed. Based on the obtained results, it can be affirmed that the radial composite is the most appropriate analytical model reproducing the phenomenon of gas mobility reduction in the nearest wellbore region.

Due to the production decline of mature fields, the possibility to drain low permeability formations became recently of great interest in the Congo basin. Some of these reservoirs can produce at economic rates only if massive hydraulic fracturing jobs are performed. In the Congo off-shore environment, the capital expenditure associated to such kind of interventions can be critical. It follows the need to accurately identify the candidates, and then properly design and model such hydraulic fractures in order to have sound production profiles for economic evaluations. Accurately modeling hydraulic fractures and mid-long term production profiles of slanted fractured wells can be extremely challenging. Analytical methods can be misleading in estimating production profiles of hydraulically fractured wells due to multiphase flow and the reservoir heterogeneity. The paper describes the successful history match process for highly deviated wells with pre and post frac production history in Kitina 3A oil field. The static and dynamic 3D model is calibrated with dynamic data with a step by step approach, starting with the data gathered in the prefrac production history. Different criteria to establish cuf off are tested in order to properly describe the reservoir net pay. The post frac data give insight into fracture properties. A huge effort has been made in order to properly modeling both hydraulic fractures geometry and conductivity in a consistent way with the data obtained with the treatment interpretation. The hydraulic fractures are described in a full field 3D model using refined grids around the wells and tuning the grid dimensions in order to have both production accuracy and acceptable run time. History match process gives indications that fracture conductivity may differs significantly compared with the value of the frac job interpretation. In addition post frac history match is improved greatly by the knowledge of formation permeability through for example well test interpretation. On the base of the experience gathered on the simulation of such wells, some general guidelines are drawn for a wider application.

Rejuvenation of mature assets plays a crucial role in current low oil price scenario, allowing improving production with limited investments and risks. Nevertheless, brown field rejuvenation is often very demanding in terms of complex integrated reservoir studies, mainly due to the huge mass, heterogeneity and reliability of available data. In this context, it is crucial to shortly identify the key parameters that allow to robustly detect the main flow paths in the reservoir, their current status and any possible optimization. An integrated workflow is proposed for brown fields where oil production is mainly driven by water injection. Produced water salinity plays a key role, acting as natural tracer whenever a huge contrast in salinity exists between formation and injected water. Production and geological data throughout all the different field deployment phases are deeply integrated. The outcomes are conceptual models where the evolution of fluid paths in time is clearly identified, providing a valuable support for both validating the geological vision of the reservoir and driving the dynamic model history match. Once the 3D model is available, streamline analysis is performed to verify its robustness, compute the efficiency of the current injection scheme and drive the deployment strategy optimization. This paper is focused on a mature Egyptian field characterized by an extremely complex heterogeneity, more than 60 years of production and about 500 wells drilled. The field is undergoing a rejuvenation process including water injection optimization and chemical EOR. Despite the amount of data, some uncertainty in the field behavior is still present, mainly due to the high impact of commingle production. Due to ESP well completions and similar oil characteristics in all layers, both PLTs and geochemical analysis could provide only a marginal support to the analysis. In this context, the proposed workflow allowed detecting the main connections without any additional data collection, thus reducing costs and timing. The results of the analysis improved the understanding of some critical aspects both on static and dynamic sides: validation of fluid contacts, well integrity issues, aquifer support, faults impact and commingle contributions. The results achieved show that in a framework characterized by the presence of a huge number of measured data, a systematic approach for their analysis and interpretation can help in extrapolating the main fluid paths from the complexity of brown reservoirs and thus providing a valuable support to speed up and optimize fields analysis and rejuvenation.

Kadanwari field in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands D-E-F-G. The gas production started from better quality E and F sands; after 2004 layer G started to drain western block of the field, with the first hydraulic fracture job made in Pakistan (well A). Layer G represents a complex target for petrophysical characterization; reservoir sandstones are micro-porosity rich, with variable presence of Chlorite affecting flow properties. Positive results encouraged the operator to drill & frac well B and to consider possibility to extend gas production throughout western block, including sand reservoirs of variable quality, from moderate to tight. The paper describes how reservoir study faced layer G complexity and how production data of wells A and B allowed a post fracjob evaluation integrating well-test data and frac-job interpretations into 3D dynamic model. After history match, the computed GOIP suggested an infilling program in G sand reservoir, with side-tracks of existing wells and new wells, all hydraulically fractured. So far, one sidetrack and one new well have been drilled; results fully confirmed the complexity of local geological setting. The sidetrack revealed rock quality slightly better than expected (frac not necessary). Pilot well C targeted G-Sand in a sweet seismic anomaly in western area, a gas flare was observed during DST pre-frac. Mini-Fall Off was conducted to estimate closure pressure and effective mobility, but permeability computed from MFO was not conclusive due to important filtrate invasion. DST post hydraulic fracture job confirmed commercial gas rate production higher than 1 MMscfd with a peak of 3.5 MMscfd. The successful pilot well results open new horizon to improve reserve from tight sand of Lower Goru formation.

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