Deepwater Turbidite Lobe Deposits: a Review of the Internship Research

Published: 2021-09-14 15:35:09
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In the first two weeks, I worked with an intern on doing a research on turbidite systems and the karish and tannin fields case in Palestine. We started by defining turbidite systems and their Architectural elements, by stating that Turbidite systems which are also known as submarine fans are defined as accumulations of clastic sediments derived from continents and deposited in deep-sea basins. In addition, they represent the transfer system of sediments between the source area (hinterland) and the depositional basin (deep-sea) and represent the most significant accumulations of siliciclastic sediments in the deep-sea. Turbidite systems are of great importance to scientists because they are potential hydrocarbon reservoirs, in addition to their contribution in the understanding of earth’s history and past climate. The architectural elements are identified based on the nature of their surface, base, internal, external and 3D geometry. They are known as: Large scale erosive features, Channels and channel deposits, Levee-over bank deposits, Lobes and Channel-lobes transition zones.
To begin with, The Large-scale erosive features are represented mainly by Canyons which are defined as narrow and deep valleys that act as a conduit to transport grains of varied sizes from the shelves to the deep sea, thus represent a main sediment source for the turbidite systems. Furthermore, channels represent important conduits of sediments within turbidite systems and they mainly transport sediments and distribute them on the continental margin with no significant effect in the deep-sea. Moreover, overbank deposits are created adjacent to main channels due to spillover and spitting of turbidity currents and they are thin-bedded sediments dominated with fine-grained sediments. In addition, Lobes are defined as lobe-shaped, thickening and coarsening upward, distal areas of turbidite system in which sand layers have largest thickness and lateral continuity, thus forming important hydrocarbon reservoir systems, while Channel-lobes transition zones that are also considered as the proximal part of the lobe domain are characterized by erosional and by-pass processes. Then we explained the Sedimentary Processes and the Controlling Factors, Sedimentary Processes contribute to the transport and deposition of deposits within the turbidite system; among the most important are turbidity flows, slumps, and mass/debris flow processes. Canyons are characterized by erosive processes, slumping and mass transport, and deposition from high energy hyper-concentrated flows that erode the seafloor sediment and mix them within the flow. Channels include depositional and erosional processes. Long and sinuous channels are characterized by low-energy flows and muddy deposits while short channels are characterized by high-energy flow and sandy deposits. Tectonics is the main factor influencing the height and location of sediment sources; distance from source to shoreline. The climatic factor exerts a major control on the weathering process and the availability of water for the flow and subaerial transport of sediments, while the sedimentary factor includes the characteristics of the grains such as size, composition, sandstone to shale ratio, sediment maturity, and the transport and distribution of the sand on the fan. Moreover, we described coarse-grained and fine-grained turbidite systems where we stated that gravel-rich submarine fans are small in size and they occur on narrow shelves, while sand-rich and mud-rich fans are connected to systems with single active channel. Therefore, the formation of sand-rich or mud-rich fans is linked to the competence (carrying capacity) of the fluid flow.Then we explained the geological setting of levant basin, it is located in the eastern Mediterranean region, and is surrounded by (1) the Cyprus and Larnaca thrust zone northwards, (2) the Eratosthenes Seamount to the west, (3) the Nile Delta deep-sea cone southward as well as (4) the Eastern Mediterranean coast. This basin was formed by consecutive of rifting, collision, and finally strike-strip deformations. We listed the Extensional phases in the Levant with NW-SE/NNW-SSE directions: the first occurred in the Late Paleozoic/Early Mesozoic. The second occurred in the Late Paleozoic/Early Mesozoic. During Triassic, a restricted depositional environment dominated along the Levant margin and appeared as evaporitic sequence. The third occurred during Early Jurassic with the deposition of pyroclastics and volcanics along the Levant margin. The early stages of the Levant basin’s formation were characterized by the formation of a shallow marine/shelf environment in the deep basin, and a fluvio-deltaic environment – shallow marine setting formed at the margins. In the late Jurassic, the rifting ceased, and a post-rift phase occurred with the initiation of passive margin. The westward-deepening slope was characterized by the deposition of marine carbonate and deep-water siliciclastic sediments. We also listed the major events that happened during the Cretaceous, Eocene, Miocene and the Pliocene periods.
Next, we discussed the Hydrocarbon Fields, Hydrocarbon Plays and the Source Rocks and Petroleum Systems in the levant region. In the Permian to Middle Jurassic interval, Triassic and Jurassic fault-related traps are suggested as the main hydrocarbon plays. These faults in addition to the Triassic and Jurassic grabens can be associated with alluvial fans (conglomerate type) or other coarse-grained clastic deposits. In Addition, In the Middle Jurassic to Turonian interval, Possible hydrocarbon plays include Deepwater fans of the lower cretaceous, Submarine canyons and channel systems of the early cretaceous with the deposition of deep-water fans sand layers and the deposition of fine-grained carbonate debris and oolitic shoals during the early-middle Jurassic period, the Syrian arc fold causes the trap of middle Jurassic reservoirs (but does not control the porous intervals). Moreover, In the Oligocene to Lower Miocene interval, the possible hydrocarbon plays are: Oligocene channel-fill and Deepwater fans, Basin floor fans at the distal end of the canyons, some fans might occur in structurally favored locations within Syrian Arc II type folds and Miocene carbonate buildups, equivalent to reef and shelf carbonate formations. Example: buildups of Jonah ridge. Similar buildups were discovered in the deep water of Nile delta. Furthermore, In the Middle to Upper Miocene interval, Possible Hydrocarbon plays include Miocene channel-fills and deep-water fans (like Oligocene play), Stratigraphic and structural plays and deepwater channels in contact with the base of the Messinian layer. While, In the Pliocene interval, a hydrocarbon play is Possible in Pliocene canyons at the southern part of the Levant basin.
The distribution and maturation of source rocks are important aspects of hydrocarbon potential of the Levant basin. The basin has two types of petroleum systems: thermogenic biogenic, they include biogenic gas potential sources that are organic rich shales of the Plio-Pleistocene; Oligo-Miocene (sadot and shiqma gas fields at the southern coastal plain); Eocene, Organic rich shale of Miocene and Pliocene source (Noa, Mari & Gaza Marine fields), Mesozoic source rocks that are associated with thermogenic petroleum systems, Senonian strata that is a potential oil and thermogenic gas source in the deep basin since Upper cretaceous sources reach maturity in the Levant basin at a depth more than 4 km, Gevar’am shale of lower cretaceous that is a potential source of oil and thermogenic gas since it has good properties of a source rock and Barnea Formation (organic rich limestone) that is a possible source of hydrocarbons if it extends to the basin. The Levant basin has similar characteristics to the Nile delta in which the deep structures act as focal points for the vertical migration of hydrocarbons producing thermogenic and biogenic gases in the shallow structural levels.
In the Tamar field, the estimated recoverable gas resources are 10 TCF. The field appraisal was associated with the development program “phase 1” and the first initial production was done in 2013. Phase 1 includes five production wellbores with production potential up to 250 MMscf/day. In addition, the field is known for an Oligocene-Miocene reservoir section defined as a sequence of deep-water turbidite sandstones interbedded with siltstones and mudstones. The sands are mainly quartz with more than 20 % porosity and permeability exceeding 500 mD. This field is classic sand –shale reservoir yet it has analysis problems of logging tool responses due to high-salinity water-based mud, and the existence of complex mudstone lithology that alters the known “shale” properties. The Tamar field is formed of large four-way anticline trap cross-cut by multiple faults.
Then we explained the reservoir geology of the Karish and Tanin fields, Hydrocarbons of Karish and Tanin fields are discovered within Early Miocene submarine fan deposits of the Tamar sands. These layers are overlying Early Miocene and Late Oligocene well-developed aquifer sands. Tamar sands are subdivided into detailed reservoir units: A-D sands and A is stratigraphically the youngest. The units are separated by pelagic shales deposited by flooding surfaces (due to maximum sea-levels and starvation of the Levant basin). Regarding the C sands, Karish reservoir is mainly massive, clean, C Sand (Tcfg of gas in place in Karish Main). The C sands are of outstanding reservoir quality, and they are extensive across the entire structure. The gas volumes in C sands are estimated to be 362bcf since most of these sands are limited to the aquifer. However, B sands are distal/marginal turbidite deposits yet relative to the C and D sands. They are related to the Early Miocene growth of the Karish Main known as the post deposition of laterally unconstrained C and D sands. Then, the dilute flows with fine grained sediments deposited the Tamar sands. As a result, the sands are thinly bedded and the net reservoir sands of the B sands are not well known. While, D sands also possess excellent reservoir qualities. A and B sands are well-developed turbidite sands with NTG >80%, and they are interpreted in the Tanin complex. C and D sands are present in Tanin and they have good reservoir quality. However, C sands are solely within the aquifer due to low structural relief.
After that we concluded our research by discussing the Lease and Petrophysical Interpretation of each field. Regarding Karish field, since top A sand was absent in the Karish-1 well and it is probably absent over the entire Karish Main Field, the downward truncating unconformity was interpreted instead. Several factors affect the quality of the Top equivalent horizon including; fault shadow, lateral velocity variations, on-lapping and erosion, and continuous high amplitude reflector. The upper C sand unit is present all over the Karish Lease with the thickest part being to SW of the lease, this layer is almost completely sandstone with a NTG of 93%. The Lower C sand unit is thinly layered with minimal thickness variations. While, the top D sand is distributed all over the lease. Three main closures encompass the Karish Field Complex, The Karish Main segment is bound to the North with the reactivated Jurassic main faults, and by Oligo-Miocene normal fault to the east. Karish North structure is connected to a smaller one to the NE having similar GWC. While, The Karish East structure is at a similar depth level to that of Karish North structure, and it is separated from the Karish Main by a NW-SE Oligo-Miocene normal fault.

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