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Reservoir Characterization of Cretaceous Mardin Group Carbonates in Bölükyayla-Cukurtas and Karakus Oil Fields, SE Turkey: A Petrographic and Petrophysical Comparison of Overthrust and Foreland Zones

By
Kadir Uygur
Kadir Uygur
TPAO Exploration Group Ankara, Turkey
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;
Huseyin Is
Huseyin Is
TPAO Exploration Group Ankara, Turkey
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;
M. Arif Yükler
M. Arif Yükler
IB A Inc. Dallas, Texas, U.S.A.
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Published:
January 01, 1997

Abstract

Approximately 95% of Turkey’s total oil production comes from southeast Turkey, with 70% of the 95% from Cretaceous Mardin Group carbonates. This study is carried out to evaluate the petrophysical and petrographic properties of the source-reservoir-seal carbonate intervals of the Mardin Group oil fields of the foreland area and oil fields of the Upper Cretaceous overthrust frontal zone of southeast Anatolia. The data include thin sections, cores and plugs, drill-stem tests, electrical logs, organic geochemistry, and basin analyses results from 65 exploration wells in both regions.

The Aptian-Lower Campanian Mardin Group is deposited on the shelf-to- intrashelf part of a passive continental margin of the Arabian plate. Relative sea level changes in the Cretaceous are responsible for three main shallowing-upward cycles that produced three reservoir intervals separated from each other by source and/or seal intervals. Each of the cycles is underlain and overlain by unconformity surfaces.

Structurally, the oil fields of the overthrust frontal zone and the foreland area studied are represented by the Cretaceous imbricated structures and the Miocene wrench system, respectively. Large accumulations of hydrocarbons have been trapped along both the east-west elongated, narrow, and asymmet-rical thrusted anticlines of the imbricated zone and the northeast- southwest-trending en echelon anticlines of the wrench system.

The source, reservoir, and seal rocks are all carbonates. The oil, which is in fractured dolomites and limestones, is 22°-35°API. Porosity, permeability, and water saturation of reservoir pay zones are 3–15%, 0.1–7000 md, and 20–50%, respectively. Secondary porosity is dominant and, in decreasing order of abundance, it occurs as dolo-intercrystalline, vugular, and fracture types.

The Mardin Group carbonates have undergone both early and late dia-genesis resulting from the existence of shallowing-upward depositional cycles and burial-tectonic stresses during the Cretaceous and Tertiary Periods. The important effects of diagenesis on reservoir quality have been fracturing and dolomitization. Intrafracture mineralization, mineral replacement, and dissolution also play an important role in determining reservoir quality. The reservoir performance, on the field scale, is good at the structurally high intervals due to increased frequency of fractures and intensified late dolomitization.

The same and/or similar static hydraulic regimes prevail in the double porosity system reservoirs in and between the oil fields. There is an increase in initial reservoir pressure with depth for both foreland and overthrust frontal zones.

The main factors affecting hydrocarbon generation in source rock for the overthrust frontal zone in the northwest and the foreland area in the southeast are thickness of both the Campanian Karadut-Kocali and the Upper Miocene allochthonous units, the thickness of the Eocene-Miocene carbonates, and clastics.

Due to gravitational segregation, the API gravity of oil decreases with depth in both regions. The API gravity of oil also decreases gradually from the overthrust frontal zone to the foreland area.

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Contents

AAPG Memoir

Seals, Traps, and the Petroleum System

R.C. Surdam
R.C. Surdam
Institute for Energy Research University of Wyoming Laramie, Wyoming
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American Association of Petroleum Geologists
Volume
67
ISBN electronic:
9781629810775
Publication date:
January 01, 1997

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