Search

The petroleum system in Central Italy and the Adriatic Sea is of great interest for future hydrocarbon exploration. However, major uncertainties remain about key risk elements such as source rock spatial distribution and maturation history, the timing of hydrocarbon migration, and the nature of migration pathways. This paper presents a new regional‐scale petroleum systems model based on an integrated inter‐disciplinary study which includes public‐domain subsurface data on key petroleum systems elements, heat‐flow and petroleum geochemical data, and an extensive set of 1D basin models. Results show the importance of the Mesozoic palaeogeographic and stratigraphic setting which was characterized by the presence of platform and basinal domains. Thermal data highlight an overall higher basal heat flow in platform domains which persist at the present‐day. Considering the geochemical and thermal characteristics of possible source rocks in the study area, the Upper Triassic Burano Formation appears to be the most likely active source rock but only in those geological domains where it has been deeply buried. In particular, source rocks reached maturity only during the most recent Apennine deformation phase in the late Pliocene/early Pleistocene, i.e. after the deposition of regional seals such as the Messinian Gessoso‐Solfifera Formation. Lateral migration is suggested to have occurred to explain most of the known oil accumulations. The margin of the Apulia Platform could have acted as a migration pathway for hydrocarbons, connecting basinal kitchens to the carbonate reservoir units at the top of the platform succession within which oil and gas accumulations have been proven. Heavy oils could represent early expulsion products from the source rock, but may also locally be a result of biodegradation due to recent partial exhumation of the traps and the loss of lighter components. The results of this study may support ongoing and future exploration efforts over other carbonate platforms in the study area, and more widely on carbonate targets elsewhere in the Mediterranean region. [ABSTRACT FROM AUTHOR]

In this work, we investigate the role of hydrocarbons in changing the petrophysical properties of rocks by merging laboratory measurements, outcrops characterization, and subsurface data focusing on a carbonate-bearing reservoir (Bolognano Formation) of the Majella massif. This reservoir represents an interesting analogue for subsurface carbonate reservoirs and is made of high porosity (up to 32%) ramp calcarenites saturated by hydrocarbon in form of bitumen. We have characterized in the laboratory density, porosity, compressive strength, Young's modulus and Poisson's ratio of both clean and heavy oil-bearing carbonate rocks of the Bolognano Formation. At ambient pressure the Vp are in the range of 3.49 km/s to 5.06 km/s for clean samples with an inverse relation with porosity, whilst the Vp range for HHC-bearing rocks are from 3.56 km/s to 4.56 km/s without any relation with measured porosity. These data show that porosity and presence of HHCs within the samples both affects seismic waves velocity. In particular, V p and the derived dynamic Young's modulus generally strongly decrease with increasing porosity for clean samples and, for a fixed porosity, tends to increase with the presence of heavy-oil. This is confirmed also at higher (up to 100 MPa) confining pressure that has not a significant effect on Vp and Vs. Cyclic loading-unloading experiments show that the average compressive strength is 25 MPa and 38 MPa and average static Young's modulus are 5.7 GPa and 9.9 GPa, for clean and HHC-bearing samples respectively. Additionally, the permanent strain is always larger for clean samples. Field work, consisting in measuring fracture orientation in 11 outcrops of the same lithology, shows that both heavy oil-bearing and clean outcrops are characterized by two main trends NW-SE and NNE-SSW. However, the spacing data show that heavy-oil-bearing outcrops are much less fractured respect to clean outcrops. This suggests, assuming that the deformation occurred under the same stress state, that heavy oil-bearing outcrops are stiffer respect to clean outcrops, as supported by the laboratory measurements. We thus infer that in the study area hydrocarbons migration predates the last stage of deformation, limiting the fracturing in bitumen-bearing portions of the Bolognano Formation. At regional scale, the presence of buried oil fields located few kilometres away from the heavy-oil-bearing outcrops and pertaining to the same petroleum system, suggests a good lateral continuity of the reservoir giving clues about the key role played by primary porosity in the secondary migration that acted in this area. • Heavy oil presence strengthens the carbonate reservoir. • Oil migration predates the last stage of deformation in the Majella Massif. • The Majella Petroleum System is laterally drained. [ABSTRACT FROM AUTHOR]

[Display omitted] • Basin modeling proved that a lateral migration occurred in the Majella Area. • Basin modeling constrained the source rock to lie below the Bonanno oil field. • Triassic anoxic basins must have a minimum width of 3 km to justify the oil volumes. • Lateral migration probably is a primary process on carbonate-ramp petroleum systems. A two-dimensional basin and petroleum system modeling approach was applied to the Burano-Bolognano petroleum system (Central Italy) to constrain some factors (position, lateral extension and maturity of the source rock, the role of fractures and faults in hydrocarbon migration) which influenced its structural evolution and the related migration pathways. The petroleum system extends from the Majella Mountain to the northern Cigno, Vallecupa, Bonanno oil fields, intensively explored during the past century. Some features, such as the location and extension of the source rock and its maturity, and hydrocarbon pathways, are still undefined. Thus, we developed a 3D geological static model of the Cenozoic carbonate succession and then, we performed basin modeling along a 2D geological section, integrating the petrophysical properties of rocks measured in laboratory. Our results prove that the Burano source rock reached a low-middle maturity, and the best representation of the actual hydrocarbon occurrences is reached when the source rock is at north of the Majella Mountain with a minimum extension of 3 km. For the BBPS a strong lateral migration and a gradual oil biodegradation towards the Majella area must be considered. Moreover, modeling results highlight a minor control of the faults on the migration in this area. This basin modeling is relevance for investigations in similar settings since carbonate-ramp reservoir studies are usually very challenging to be correctly modeled due to their high heterogeneities. [ABSTRACT FROM AUTHOR]

Despite data coming from fully developed oil fields are fundamental to validate reservoir models, they are rarely publishable because of confidentiality. In this work, we benefit from an exceptionally dense public dataset represented by 43 wells logs drilled in a carbonate-heavy oil-rich reservoir of the Majella Mountain (Central Italy) over a grid of 200 m × 200 m, with depths in the range of 90–200 m. We tested different modelling solutions, to assess the best modelling approach that fits the available data on hydrocarbon distribution. Both deterministic (using Kriging) and stochastic simulations (using Sequential Gaussian Simulation- SGS) were tested. The role of the variogram resulted as a fundamental parameter for both simulation methods. Wells-derived variogram agrees with the size and orientation of carbonate dunes that drive the hydrocarbon distribution highlighting the importance of an accurate depositional model. Kriging was faster in terms of computation time and better in maintaining the lateral continuity of the layers, however, it excessively smoothed the results. SGS gave a better distribution of computed values but the lateral continuity was not preserved. By adding a main vertical trend derived from the upscaled logs to the SGS, results become more accurate. We then applied the best model to estimate the total volume of hydrocarbon in place in an already exploited area starting from just one well. The computed reserves show a good fit with historical production data demonstrating the reliability of the model. • We benefit from a public dense well dataset to test carbonate-reservoir models. • Deterministic solutions are faster but mostly inaccurate. • Stochastic simulation with vertical trend improves simulations of single well profile. • Variogram shape is crucial to improve the 3D stochastic simulation results. • Wells-derived variogram agrees with size and shape of carbonate dunes. [ABSTRACT FROM AUTHOR]