Hydrocarbon Charge and Reservoir Pressure History of the Carbonate Stringer Play in South Oman - Implications for Pre-Drill Pore Pressure Risking

Taylor, Paul N.; Harrasi, Afifa Al; Eden, Cees van; Ghammari, Mohammed Al

doi:10.3997/2214-4609-pdb.248.043

Cited by 3 publications

(2 citation statements)

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“…The most likely process leading to the formation of reservoir bitumen in our study area is a rapid pressure reduction. Taylor et al [69] argue that gas-condensate accumulations in Ara reservoirs originate from former oil phases that were subjected to a rapid change from litho-to hydrostatic pressures. Kukla et al [7] proposed that such a pressure deflation event would have affected oil-bearing carbonate stringers in the terminal salt tectonic phase, when the overpressured reservoirs came in contact to the siliciclastic minibasins (Figures 3 and 13).…”

Section: Diagenetic Processes and Fluid Composition During Deepmentioning

confidence: 99%

Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)

et al. 2019

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A common problem in dolomite reservoirs is the heterogeneous distribution of porosity-reducing diagenetic phases. The intrasalt carbonates of the Ediacaran-Early Cambrian Ara Group in the South Oman Salt Basin represent a self-sourcing petroleum system. Depositional facies and carbonate/evaporite platform architecture are well understood, but original reservoir properties have been modified by diagenesis. Some of the carbonate reservoirs failed to produce hydrocarbons at acceptable rates, which triggered this study. The extent of primary porosity reduction by diagenetic phases was quantified using point counting. To visualize the distribution of diagenetic phases on a field scale, we constructed 2D interpolation diagenesis maps to identify patterns in cementation. The relative timing of diagenetic events was constrained based on thin-section observations and stable isotope analyses. Near-surface diagenesis is dominated by reflux-related processes, leading to porosity inversion in initial highly porous facies and a patchy distribution of early cements. This strong diagenetic overprint of primary and early diagenetic porosity by reflux-related cements leads to a reduction of stratigraphic and facies control on porosity. Calcite was identified as a burial-related cement phase that leads to an almost complete loss of intercrystalline porosity and permeability. Bitumen is an important pore-occluding phase and time marker of the deep-burial realm. The stratigraphic position of the dolomite reservoirs embedded at the base of a salt diapir had a strong impact on its diagenetic development. The salt isolated the dolomites from external fluids, leading to a closed system diagenesis and the buildup of near lithostatic fluid pressures. In combination, these processes decreased the impact of further burial diagenetic processes. The study highlights that cement distribution in salt-encased carbonate reservoirs is mainly related to early diagenetic processes but can be very heterogeneous on a field scale. Further work is needed to implement these heterogeneities in an integrated numerical reservoir model.

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Section: Diagenetic Processes and Fluid Composition During Deepmentioning

confidence: 99%

Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)

et al. 2019

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“…Two crucial factors, reservoir qualities and structural activities, dominate the development of the most conventional oil and gas fields (Elsebakhy et al, ; Guan, Srockmeyer, Shaw, & Plesch, ; J. Guo, Wang, & Pang, ; H. Y. Hu & He, ; Hubbard, Edrich, & Rattey, ; Ibrahim, Khan, & Khatib, ; Y. Qiu, ; Quirk, Roy, Knott, Redfern, & Hill, ). High‐quality reservoirs with high porosity and permeability support the hydrocarbon charging and escaping (Smith & Ehrenberg, ; Taylor, Harrasi, Eden, & Ghammari, ). The oil and gas also have preferences for reservoirs with high porosity and good connectivity in the Junggar Basin (Z. H. Bai et al, ; Cao et al, ; Hao, Zhang, Zou, Zhang, & Yang, ; Shao, ; Xiang, Zhou, Ma, Wu, & Cao, ).…”

Section: Introductionmentioning

confidence: 99%

The diagenetic and tectonic significance of hydrocarbon accumulation in the southern Junggar Basin, NW China

Tian

Zhang

et al. 2017

Geological Journal

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The Jurassic petroleum system plays an increasingly important role in petroleum explorations in the southern Junggar Basin. To assess the hydrocarbon distribution and the accumulation history of the Jurassic reservoirs in this area, we carried out reservoir petrographic, fluorescence spectroscopic, and fluid inclusion petrographic analyses on the core and cutting samples from the QQ‐2 well in the Qigu Anticline. The oil accumulation has the partiality for high‐quality sandstone reservoirs that have the high porosity and permeability with values of 14–18% and (1–450) × 10−2 μm2, respectively, in the Middle Jurassic Toutunhe Formation (J2t) reservoirs. The pores are big with average diameters of 60–100 μm, and the pore throats are wide with values of 3.45–6.92 μm in the oil reservoirs. The intergranular pores survive thanks to the poor compaction and the poor cementation, and the dissolved and mould pores develop attributed to the strong dissolution in the oil reservoirs. Two episodes of oil charging and one episode of gas invasion were identified in the Middle Jurassic reservoirs in the southern Junggar Basin. The low‐maturity paleo‐oil charged the sandstone reservoirs at about 35 Ma when the paleo‐traps took shape during the Cretaceous–Eocene. A large number of faults and anticlinal traps was developed in the southern Junggar Basin at about 7 Ma, caused by the reactivation of the Tianshan Mountains in the late Cenozoic. Simultaneously, the leakage of the paleo‐oil, the accumulation of late oil, and the gas invasion all took place. Fault activities led to the leakage of paleo‐oil and helped the oil and gas accumulate in the Middle Jurassic reservoirs in the anticlinal trap shaping at about 7–8 Ma in the southern Junggar Basin.

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Pre-Salt Limestone Plays in Campos and Santos Basins, Brazil: Additional Potential Identified

Kattah

2015

Day 1 Tue, October 27, 2015

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This study summarizes the pre-salt hydrocarbon play elements in Brazilian offshore and identifies additional exploration potential within the BMS-50/52 and BS-1_South 3D seismic surveys areas within the Santos Basin and of the BC-200 merged and reprocessed PSDM survey located within the deep to ultra-deep waters of the Campos Basin. Several large opportunities have been identified based on seismofacies recognition and preliminary seismic interpretations of 3D Multi-Client PSDM surveys.The BMS-50/52 and BS-1_South 3D surveys are within the pre-salt play polygon of the Santos Basin.

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Hydrocarbon Charge and Reservoir Pressure History of the Carbonate Stringer Play in South Oman - Implications for Pre-Drill Pore Pressure Risking

Cited by 3 publications

References 0 publications

Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)

Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)

The diagenetic and tectonic significance of hydrocarbon accumulation in the southern Junggar Basin, NW China

Pre-Salt Limestone Plays in Campos and Santos Basins, Brazil: Additional Potential Identified

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