In the last years, hydraulic fracturing (HF) has reached maturity, becoming a fundamental aspect of hydrocarbon productivity enhancement and an important component of well costs. Interest on HF has also increased following unconventional resources exploitation, where commercial hydrocarbons rates cannot be otherwise achieved. This work reviews and compares various methods to model HF using conventional reservoir simulators.Three different simulation solutions were investigated in this paper: i) explicit fracture representation through very detailed local grid refinement (LGR), ii) implementation of embedded discrete fracture models (EDFM) in conventional corner point geometry (CPG) grid and iii) definition of equivalent fractured wells (EFW) where the artificial fractures are assumed under hydraulic equilibrium with the wellbore.The most common HF modelling methodology consists in the explicit fracture representation by means of LGR. This approach, however, is computationally expensive for full-field models where a large number of HF wells is implemented. Moreover, fracture orientation is constrained by the geometry of the grid, while the actual orientation is due to well trajectory and stress regime. To overcome these issues, an alternative solution was proposed, based on the implementation of Embedded Discrete Fracture Model methodology (Li and Lee (2008)). EDFM allows using a coarser grid resolution with respect to conventional LGR representation. Moreover, it accounts for fracture representation regardless grid orientation. EDFM enabled a smoother and faster process for both calibration and forecast steps, facilitating the implementation of HF wells in coarse simulation grids. The modelling could be further optimised assuming that hydraulic equilibrium between well and fracture is achieved in a negligible time-scale. This allowed using the equivalent fractured well methodology, where fractures are incorporated in the well itself as additional connections. EDFM estimates of fracture-to-matrix connectivity can be used as input for EFW. This paper presents a comprehensive review of the various tools adopted to model HF in reservoir simulation and, for the first time, a thorough comparison of their effectiveness and efficiency in a real case study. Explict representation by means of LGR, EDFM and EFW were used to simulate a 3-stage hydraulically fractured horizontal well in a tight gas condensate reservoir, including well-test and long term forecast simulation cases. The benefits of each solution are compared in terms of accuracy, computational efficiency and ease of implementation. Numerical results indicated that EDFM and EFW represent powerful solutions for investigating the benefit of HF campaigns in unconventional reservoirs. Moreover, a novel combination of EDFM/EFW with moderate LGR has been investigated in order to achieve an optimal compromise between efficiency and accuracy. Eventually it provides with useful best practices/recommendations for general HF well simulation applications.

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.

Proper reservoir characterization and sweet spots identification for unconventional reservoirs need to be performed considering both geomechanical and petrophysical properties. This paper describes the integrated application of tools and technologies developed within eni internal research project on US Barnett shale gas. eni shale gas reservoir modeling has been performed by using a geologic workflow to link the petrophysical characterization and the seismic data at wellbore scale and consistently distribute these properties at field scale by means of a seismic "trend". This is the key to obtain a predictive geological model. In addiction, an engineering workflow that merges hydraulic fracture treatment, microseismic survey and advanced production analysis (APA) was set up. Thus the input parameters for dynamic simulation, focusing on the stimulated reservoir volume (SRV) estimation, may be obtained. A sector model was extracted from the full field geological model for dynamical simulation purposes. A "single porosity-like" approach was adopted to couple the advantage of dual permeability and single porosity models. As a first step, the History Match (HM) of gas production data and flowback water rates, was performed both at single well and pad scale. This allowed the tuning of SRV extension and permeability of the induced fractures. In addition, a comparison of gas reserves obtained by decline curve analysis and simulation model was performed. Moreover, by using the calibrated sector model, a series of sensitivities was carried out focusing on well landing and spacing in order to achieve an optimal pad design. The strength of this study lies on the integrated model approach. It is an efficient tool to drive and optimize the field development plan, allowing the definition of optimal wells spacing and lateral length, positively affecting economics. Finally, it is a robust approach to reduce uncertainties in gas reserves assessment. Introduction The largest part of global discovered hydrocarbon resources is stored in so called Unconventional reservoirs, that need advanced technologies, such as horizontal wells, multistage completion and hydraulic fracturing, to be successfully exploited at economic rate. This work focuses on unconventional gas shale reservoirs that are present worlwide. Nowadays, many efforts are ongoing in order to better understand their nature and the complex physical phenomena involved in the production, thus improving field development strategies. A fully integrated static and dynamic workflow for shale gas modeling was internally developed by eni. The aim was to deliver a more structured and business oriented technology to build a reliable and predictive model able to support and optimize management decisions in such complex systems (e.g. sweet spot definition, well positioning, completion, Both static and dynamic conventional workflows had to be tailored on unconventional context. In static simulation, differences are related to facies characterization and hydrocarbon volume in place calculation; dynamic simulation had to be adapted and improved to reproduce the hydraulic fracture explicitly, to model the frac fluid flowback, to consider gas desorption and multiscale fluid flow.

During the last years, oil Majors have been struggling trying to make the unconventional business profitable. Indeed, the strategy to build an unconventional portfolio by means of merges and acquisitions is not giving enough return of investment. This is mainly due to internal processes, which contrary to Independents, are customized on a very different business model.In addition, it is becoming clear that unconventional resources cannot be considered and developed as "statistical" ones. Nowadays, several publications are stating that only a small percentage of fractured wells is generating positive return. Even though unconventional reservoirs are considered more complex than conventional ones, less efforts are unjustifiably applied for their understanding. Hence, there is a need to switch from a "drill baby drill" to a "more from less" approach. This implies to address several issues such as: a better understanding of shale gas production mechanism at nano-scale, sweet spots identification, proper fracture placement and treatment, realistic full field simulation of fractured wells. This paper describes how seismic-reservoir integration, advanced production analysis, accurate nanoscale and 3D full field simulations may address the above issues and help oil Companies to be more efficient in developing their unconventional portfolio. This new approach, based on placing and fraccing wells only where needed, is already providing interesting results in mature plays like the Barnett Shale and will be even more crucial for sustainable unconventional developments outside US.

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