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In this work, we address the challenge of modelling a complex, carbonate reservoir, where the fractures network, connected throughout a complex fault framework, represents large part of both the storage and the flow capacity of the system. The asset is a giant, onshore field, developed since the 90's by primary depletion through several horizontal wells, targeting anomalous fluid columns. Different culminations are characterized by specific production drive mechanisms. The objective is to integrate an impressive amount of data into a digital model, suitable to understand fluid flow behavior and support decision. The field is challenging in every geological and dynamic feature. The reservoir complexity ranges from the intricate structural framework (several hundreds of reverse faults), to the puzzling fractures network at different scales, to the unclear role of the low-porosity rock matrix, to the heterogeneous distribution - both laterally and vertically - of fluid properties, related to different combinations of hydrocarbon and acid components. The workflow is based on the adoption of Volume Based Modelling (VBM) to account for seismic faults. Then, large-scale fractures are modelled using a blend of stochastic and deterministic Discrete Fracture Networks (DFNs), while background fractures (BGF) are characterized using a Continuous Fracture Modeling (CFM) formulation. A Dual Porosity - Dual Permeability (DPDK) approach is then implemented for reservoir simulation. The model is finally reconciled with the production data by iterating between geology and simulated dynamic response. The whole modeling and simulation workflow, from static to dynamic model definition, is developed relying on company's top-class computational resources. The DPDK formulation, where DFN is the second medium while the first medium consists of BGF and rock matrix, allows us to simulate the main production mechanism: large-scale discontinuities – DFN – are withdrawal first, and then fluid is recharged by smaller scale features. Besides, the history matching phase, together with accurate production and Pressure-Volume-Temperature (PVT) data analysis, sheds light on the extreme heterogeneity of the field. Petrophysical properties, storage and effective apertures of discontinuities are calibrated according to the production history, and integrated into a comprehensive understanding of the reservoir. Eventually, we reveal how a robust history matched model may be used as a powerful tool to understand the impact of all the involved criticalities on the subsurface fluid behavior and movement in a complex fractured carbonate setting. The challenges addressed in this work provide relevant best practices for carbonate reservoir modelling, in particular highlighting the role of the integration between geology and reservoir engineering to minimize subsurface uncertainties. Furthermore, the PVT model developed in this study proposes new migration scenarios to explain the sour gas distribution. Finally, optimized procedures to tackle numerical criticalities using advanced reservoir simulators are disclosed.

Enhanced Oil Recovery through CO 2 injection allows to reach a twofold valuable objective, increasing the amount of crude oil extracted from an oil field while mitigating the contribution of emissions to global warming. Such an intervention is planned in an oil production field in Sicily (Italy) by employing a CO 2 stream already available from an oil refinery located near to the field. The oil is currently produced through a pump artificial lift and fluidized by a fluidizing stream injected at the bottom of the well, due to its characteristics: it is an heavy, asphaltene-rich oil. Just these characteristics worried about the possibility that injected CO 2 could destabilize the asphaltene fraction, leading to the formation a of a sludge or a solid phase, that would plug the formation pores and, ultimately, decrease injectivity and productivity. In order to assess this risk, the eni in-house-developed asphaltene deposition model was employed to investigate various conditions close to the expected operating conditions. At the same time, a lab activity was undertaken, in order to have an experimental check at least on a narrow range of conditions. Results of these activities showed that no deposition happens in the expected range of operating conditions. A description of both simulation and experimental activities is reported, in order to show how it is possible to assess the risk of asphaltene deposition before operations potentially dangerous to the field productivity. Case studyThe field object of this study lies in south-east Sicily and has been discovered in the early '80. Heavy oil mineralization (API gravity around 10°) has been detected both into a lower dolomites formation (300 cp viscosity at reservoir conditions) and into limestones of the overlying formation (40 cp viscosity at reservoir conditions). The reservoir depth is more than 3200 mssl, corresponding to an initial pressure and temperature of 326.5 bara (@3200 m) and 102 °C, respectively. The lowermost formation has been put in production in September 1990 with the drilling of five wells, one of which has been sidetracked in 2003. The uppermost formation has never been put in production. In order to optimize the investment, a study has been performed to evaluate carbon-dioxide injection scenarios for the field (both formations), which could be implemented. The reservoir is characterized by the following geological features: complex and interacting processes of initial facies deposition, progressive faulting/fracturing and several diagenetic phases of secondary porosity creation; oil migration through the fracture system only. The relevant conceptual model can be summarized by the existence of two main flow components: one vertical (fracture corridors) and one layer-driven (pseudo-matrix system, i.e. an interaction between macro-meso porous system and diffuse fractures). In order to improve the oil recovery factor, CO 2 injection was proposed, as it is possible to have a CO 2 stream from a refinery plant located near the field. The best CO 2 injecti...

The knowledge of reservoir fluids phase behavior has always played an important role in oilfield development planning, reserves evaluation and screening of the potential for enhanced oil recovery. Nowadays operators aim more and more at fast-track development of discovered resources, therefore, any anticipation of thermodynamic properties is a business challenge: looking for "PVT-analogues" is the solution proposed in this paper. What adversely impacts massive scouting of PVT data usually is the limit of a small amount of readily available information, also due to the intrinsic complexity of the datasets and of the variety of output formats produced by different laboratories all over the world and over the years. In Eni a new tool for data mining based on the reorganization and thorough digitalization of the PVT archive is in advanced development. Standardization of the laboratory outcomes by templates, automatic loading into a corporate repository, in-house development of software tools for quality control, data mining and advanced statistical analyses, easy access through a properly designed interface: each of these steps is integrated in an upgraded data-driven approach to fluid properties prediction allowing an earlier understanding of the reservoir fluid system.

With the aim of improving the understanding of production behaviour in a multi-discovery asset and the evaluation of near-field exploration opportunities, an integrated study has been carried out involving three different disciplines: Fluid Thermodynamics (PVT), Organic Geochemistry and Petroleum Systems Modelling (PSM). The synergistic workflow has been undertaken starting from an accurate quality check of the initial dataset related to fluid samples and lab tests. By merging PVT and geochemical data, it was possible to carry out a robust statistical survey and explore correlations across different parameters and features; in this way, strict connection among many physical parameters and some oil maturity and biodegradation indices were identified. In the following step, after geo-referencing the fluid samples in the framework of the Petroleum Systems Model and tracking the locations of the source rocks, a reliable interpretation of the oil expulsion and migration history became possible over the whole reservoir fluid system. Finally, taking into account the simulated fluid phase envelopes, further insights were drawn in terms of the fluid phase behavior in different areas, contributing to reduce uncertainty and exploration risk for future activity in nearby prospects.