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The Early Jurassic dolomitized carbonates are a hydrocarbon exploration target in Northern Italy. Of these carbonates, the Liassic Albenza Formation platform and the overlying Sedrina Formation shelf were studied to define a pervasive dolomitization model and to shed light on dolomite distribution in the sub‐surface. Field work, as well as analyses of well cores, stable isotopes, trace elements and fluid inclusions, was carried out on the outcropping thrust belt and sub‐surface deformed foreland of the Southern Alps. Petrographic analyses showed a first, pervasive, replacement dolomitization phase (D1) followed by volumetrically less important dolomite cement precipitation phases (D2, D3 and D4). The δ18O values fall between −8·2‰ and 0·1‰ Vienna‐Pee Dee Belemnite with the more depleted samples belonging to dolomite cement‐rich dolostones; the δ13C ranges from 2·6‰ to 3·7‰ Vienna‐Pee Dee Belemnite. Analysis of trace elements showed different Fe and Mn contents in the sub‐surface and outcropping dolostones, and a higher Fe in the younger dolomite cements. An increase in the precipitation temperature (up to 130 °C from fluid inclusion data) and a decrease in diagenetic fluid salinity (from sea water to brackish) are observed from the first pervasive replacement dolomite to the dolomite cement phases. Field observations indicate that, in the Albenza Formation, dolomitization was limited to palaeohighs or faulted platform margins in the Early Jurassic carbonates. The pervasive replacement phase is interpreted based on a ‘compaction model’; the formation fluids expelled from compacting basinal carbonates could have funnelled along faults into permeable palaeohighs. The high homogenization temperature of the dolomite cements and decreased salinities indicate precipitation at great depth with an influx of meteoric water. These data, along with the thermal history, suggest that the dolomite cements precipitated according to the ‘tectonic squeegee’ dolomitization model. The dolomite precipitation temperature was set against the thermal history of the carbonate platform to interpret the timing of dolomite precipitation. The dolomite precipitation temperatures (90 to 100 °C) were reached in the studied formations first in the thrust fold belt (Early Tertiary, 60 Ma), and then in the foreland succession during the Late Tertiary (10 Ma). This observation suggests that the dolomite precipitation fronts moved southwards over time, recording a ‘diagenetic wave’ linked to the migration of the orogenic system. Observations suggest that the porosity increased during the first phase of replacement dolomitization while the dolomite cementation phases partially occluded the pores. The distribution of porous dolomitized bodies is therefore linked to the ‘compaction dolomitization’ model.

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In the last period with the rising price of oil and gas, the exploration and development of unconventional plays, that are already an economic reality in North America, are gaining more attention worldwide. It is common opinion that Gas Shale reservoirs are not peculiar only to the North America Basins. ENI E&P has focused attention on this type of unconventional reservoir, both in new countries and in the areas where it has historically been successful in conventional plays and where large amount of data are available. New wells drilled in North Africa, planned to discover conventional hydrocarbon-bearing sandstone layers in the Silurian and Ordovician formations, have also been used to characterize in detail the Silurian Hot Shale that was normally interpreted as source rock. A dedicated data acquisition strategy was planned (logs and core) and, consequently, interpretation was carried out with the specific aim of characterizing this unconventional Gas Shale reservoir. This paper documents the workflow used to characterize this unconventional reservoir. It will examine in detail the wireline log interpretation based on integration with the experimental data from core. A robust characterization of a gas shale reservoir basically starts from core analysis (geochemical, petrographical, mineralogical and petrophysical) that are used for calibration and integrated in the wireline log interpretation. The benefits of these results will provide better evaluation of the hydrocarbon potential of Hot Shale in this area.

The study of the diagenetic processes is a fundamental step to achieve a more accurate and reliable prediction of flow performance, as diagenesis alters the original relationships between depositional facies and petrophysical properties. Thence, a quantitative integration of all data and available analysis is a key-factor to obtain a realistic reservoir model. A new integrated approach for diagenesis characterization and simulation is here presented. An application case was performed on the silici-clastic Egyptian reservoir of Baltim starting from quantitative diagenetic data. Chlorite content, which is here strictly related to grain size, affects the overall reservoir permeability. Particularly, "pore filling" type chlorite is responsible for the flow performance deterioration. A relationship between diagenesis and log data was defined using density and spectral gamma ray (thorium) logs as predictors of pore-filling chlorite. A good relationship was also observed between grain size and the previously defined log-facies from multivariate statistical processing (cluster analysis), enabling us to assign a well defined depositional meaning to each of them. The right evaluation of the petrographic-diagenetic input represents an excellent "starting line" for the following phases. First, a traditional reservoir workflow (pre-diagenesis characterization) has been carried out testing different geostatistical facies simulations approaches (Sequential Indicator Simulation, Object Based Approach, Truncated Gaussian Simulation, Pluri Gaussian Simulation and Multiple Point Statistics). Then, a new methodological workflow for post-diagenesis reconstruction has been implemented, using a matrix that combines sedimentological information and diagenetic indicator at wells. Finally the petrophysical parameters have been simulated classically according to the characteristics of each post-diagenesis facies. The results, compared to well test permeability and analysed with the flow simulator, show a good to very good match with the measured data. The match quality is clearly dependent on the mutual consistency of the facies distribution and the conceptual sedimentological model conditioning diagenetic effects.