Eastern Mediterranean Workshop 2018

The evaporite-dominated Messinian sequence is lithologically heterogeneous as halite is interbedded with other salts, in addition to clastics or carbonates. This lithological heterogeneity can lead to rheological heterogeneity, and the different mechanical properties of the various rock types controlling strain partitioning within deforming evaporites. Determining the composition and internal structure of salt bodies is important for safe drilling through thick salt sequences, and enables us to build better velocity models that allow more accurate seismic imaging of subsalt geology. However, due to typically poor seismic imaging, and a lack of outcrop and well data, the nature of this lithological control on intrasalt deformation is poorly understood. We use high-quality 2D and 3D seismic reflection data to map intrasalt structural style, and horizontal and vertical variations in strain. This enables us to determine how lithological and thus mechanical heterogeneity affects the structural evolution of the salt during early stage salt tectonics.

Despite lying in the neighbourhood of one of the most prolific petroleum provinces of Africa, Egypt’s West Mediterranean Sea has seen exploration efforts limited by a lack of data and clarity of license block delineation. Recently acquired long offset GeoStreamer® seismic data, together with anticipated licence round activities has suddenly thrust this area to the forefront of oil companies exploration plans in 2018. Additional 2D acquisition has also started across this frontier area further increasing seismic coverage, this data will be available prior to the announcement of the first license round offshore west Egypt The area can be divided into several geological domains with multiple play types observed across the shelf, the transform margin and the basin. Analogous plays and structures have been linked to the producing onshore western Desert, the prolific Nile Delta pre & post salt biogenic plays and isolated carbonate features that have similar characteristics to that of Zohr. It is believed that Egypt’s West Mediterranean Sea contains all aspects relevant for a potentially prospective working petroleum system(s). Therefore, Offshore West Egypt is rapidly attracting attention as a potential new petroleum province in the Eastern Mediterranean.

This paper suggests that the carbonate units south of the Kefalonia Transform Zone (KTZ) ( Scordilis et al., 1985 ) bear similarities to the northern Paxi formations. From North to South and crossing the KTZ, we encounter sharply, from the Apulian Platform north of the KTZ, the Mediterranean Ridge, the backstop, the Hellenic Trench and the Hellenides Thrust and Fold Belt (TFB), south of the KTZ. Interpretation of data based on the 2012–2013 MC 2D seismic acquisition of PGS.

The complex geological history of the Eastern Mediterranean, in combination with the unique event of the Messinian Salinity Crisis (MSC) favored the creation of an active petroleum system. This study focuses on the deposition of clastic sediments during the Messinian Salinity Crisis, in the South-West Exclusive Economic Zone (EEZ) of Cyprus, highlighting the potential prospects of the Messinian low-stand incised valley/submarine canyon play and taking into consideration the salt tectonics of the region. After the interpretation of 2D seismic data, the results show that the Messinian clastic sediments derived from the River Nile during the forced falling regressive system tract (FFRST) deposited strictly west of the West Eratosthenes High in the deep Herodotus Basin and have a thickness of approximately 2 km in South-West EEZ of Cyprus. These clastic accumulations represent the distal sand sheets of the Nile Cone and are important regarding the petroleum plays in the area. Finally, the northern gliding of the Messinian Evaporites from the Nile Cone to the deep Herodotus Basin was controlled by the Pre-Messinian topography and can justify the absence of any bathymetric scar from the west side of the Eratosthenes Continental Block (ECB).

The Maltese Islands have a long hydrocarbon exploration history, but with limited success, so far. However, as the southern part of the Ragusa plateau (Hyblean foreland) has major oil fields offshore Southern Sicily it should be considered as prospective region. In terms of prospectivity, the area in the south is surrounded by proven petroleum systems and shows; and from an exploration point of view, with important analogies to the well-known offshore Tunisia and northern Libyan petroleum provinces. In the north, the area is next to offshore southern Sicily with well-known large oil fields on the Ragusa plateau. Offshore Malta is covered by several seismic vintages of 2D data (WG and TGS). Interpretation of 2D, both structural and stratigraphic, delineates a better understanding of the individual petroleum systems within the area. The objective of the study is to summarize the results of the interpretation completed by WG and TGS tying areas covered by both parties’ seismic, extrapolate the findings across the plays and leads identified on seismic offshore Malta and update our insight with new petroleum system analyses, to assess the geological evolution of the area, and give our perspective on the exploration potential of this under-explored area.

Recent large sub-salt discoveries in east Mediterranean waters have steered the focus on imaging beneath complex salt structures, where the main challenge is to correctly illuminate the sub-salt section. This involves optimizing acquisition parameters as well as building an accurate subsurface geological model. Only limited regions in the east Mediterranean are covered by multi-azimuth surveys; most of the 3D surveys available are narrow-azimuth. A lack of data diversity degrades the imaging of sub-salt zones even when using accurate subsurface models. Optimal model building for depth imaging involves the application of many complimentary imaging technologies to mitigate assumptions in any singular process. Illumination issues in the east Mediterranean are primarily caused by the complex interaction of shales and salt. The geometry of the salt layer and the velocity contrast across neighbouring lithologies determine the illumination and imaging quality beneath the salt layer. Using accurate interpretation of the top and base salt, and inserting a reliable velocity in the model, enhances the sub-salt imaging. This work focuses on the salt layer model building in three zones across the east Mediterranean Sea and the optimization of the salt/shales, and salt/carbonates velocities to enhance the sub-salt imaging and improve the reliability of amplitude data.

Over the recent years, in a context of oil price instability faced by resiliently-high operational costs, all exploration risks need justification via thorough analysis performed on all the available data. In such contingency, re-processing with modern techniques all the accessible seismic surveys, even if very old, helps to retrieve the maximal information on the subsurface, fostering the decision-making process and the de-risking of successful exploration activities. The main objective of the presented study is the broadband processing of a technically- and geologically-challenging vintage marine 3D dataset from the Mediterranean Sea, via modern Pre-Stack Time Migration. The main geological target for the reprocessed dataset is represented by fractured Jurassic limestones. Severe seismic challenges are posed by the obsolete and unconventional acquisition pattern, along with the multiples and reverberations offered to the seismic image by the shallow-tilting and high-impedance Messinian salt/evaporites. The authors hereby present a modern, innovative, and rigorous broadband re-processing for the improved imaging and illumination of the subsurface, applicable to all Mediterranean provinces.

The recent seismic data offshore Greece revealed, south of Crete, the presence of an external Hellenides carbonate unit similar in dimensions to this of the island of Crete. Velocity modelling helps in this study to emphasise the tectonic-stratigraphic image below the seafloor at depths reaching 9 kilometres.

For any reservoir engineering issue or manage production from the petroleum reservoir, it is required to have seismic characterizations in quantitative manner, rather than qualitative geological interpretations. Herewith, seismic inversion could assist reservoir engineer as the technique to transform seismic data to quantitative rock properties. General steps in interpretation of seismic data preparing for porosity estimations consist of seismic structural interpretation, inversion procedure and attributes analysis. Since there is no direct measurement for the lithological parameters, they are to be computed from other geophysical logs or seismic attributes. This process also requires repeated intervention of the experts for fine tuning the prediction results. Standard regression methods are not suitable for this problem due to the high degree of the unknown nonlinearity. The problem is further complicated because of uncertainties associated with lithological units. In this context, Artificial Neural Network is considered to be useful tools to establish a mapping between lithological and well log properties. In this study, a strategy is presented for defining 3D seismic reservoir porosity model based on advanced method of artificial intelligence (AI) concept. This strategy then would be applied on a complex and heterogeneous oil reservoir which is a relatively symmetrical anticline whose trend is N-S. Required input data was prepared by seismic attribute and the velocity was modeled by vertical seismic profiling data. The general characterization strategy followed by initial inversion model construction for acoustic impedance of total cube for the target formation. Consequently, initial inversion model for effective and total porosity of the target formation was obtained. Acoustic impedance logs were used for neural network training and the genetic algorithm were used for calculation. High correlation values around 86% in cross plots, confirm accuracy of the porosity estimation by the AI method. This model then was used to precise the geological and geometrical properties of the reservoir for well location proposal.

Nowadays oil and gas exploration and production is often performed in geomechanically challenging enviroments. Choosing the right scale and complexity of a model is critical for performing an effective and efficient geomechanical analysis. In this paper different geomechanical modeling techniques are compared for their accuracy and efficiency using a relatively simple (continental slope) and a more complex geological setting (submarine canyon). This was done by comparing the resulting state of stress of 1D well-centric geomechanical models with those of reservoir-scale 3D geocellular and 4D finite-element models. The more complex submarine canyon model shows that in relatively complex areas the 1D and 3D geomechanical models no longer give accurate stress results and a 4D model is needed to accurately simulate the state of stress. On the other hand, the continental shelf model shows that in a simple geological setting creating a 1D wellbore-scale geomechanical model is an efficient and effective way of calculating stress. The paper concludes that the initial step in a geomechanical study is assessing the geomechanical application of the model, taking the complexity of the geological setting into account and based on that assessment choosing the modeling complexity that is necessary to get accurate results, without unnecessarily spending resources.