Journal of Petroleum Geology最新文献

Carbonates in the Lower Cretaceous (Barremian to early Aptian) Kharaib Formation are reservoir rocks at giant oil fields in the UAE and Qatar. The Barremian Kharaib-2 member (K60), the focus of this study, is in general composed of a regionally continuous succession of high-energy, shallow-water limestones bounded above and below by “dense” low-energy mud-rich strata. Despite several decades of research, conventional carbonate facies classification schemes and resulting facies groupings for the Kharaib-2 member have failed to show a statistically acceptable correlation with core- and log-derived petrophysical data. Moreover, sedimentary bodies potentially responsible for dynamic reservoir heterogeneities have not clearly been identified. This paper proposes a standardized facies classification scheme for the Kharaib-2 carbonates based on vertical facies proportion curves (VPCs) and variogram analyses of core data to construct stratigraphic correlations at both field and regional scales. Data came from 295 cored wells penetrating the Kharaib-2 member at ten fields in the on- and offshore UAE. Thin, dense intervals separating reservoir units were adopted as fourth-order transgressive units and were used for stratigraphic correlation. Field-scale probability maps were used to identify sedimentary bodies such as shallow-water rudistid shoals.

Regional stratigraphic correlations of the Kharaib-2 member carbonates based on the VPCs identified variations in depositional environments, especially for the lower part of the reservoir unit; depositional facies at fields in the SE of the UAE were interpreted to be more distal compared to those at offshore fields to the NW. At a field scale, the VPCs failed to identify significant lateral variations in the carbonates. However, variogram analyses of cored wells showed spatial concentrations of specific facies in the inner ramp domain which could be correlated with high-energy depositional bodies such as shoals dominated by rudist debris. The bodies were sinusoidal in plan view with lengths of up to 8 km and widths of ca. 1 km. Although similar-shaped bodies with these dimensions have been reported from other carbonate depositional systems, they have not previously been reported in the Kharaib Formation. At a regional (inter-field) scale, the stratigraphic correlation of standardized sedimentary facies remains problematic; however, mapping of facies associations and their relative proportions relative to their environments of deposition demonstrated new patterns for the stratigraphic architecture of the Kharaib-2 member in the UAE.

We review published studies characterizing the Thamama-B reservoir zone in the upper Kharaib Formation (late Barremian) in Abu Dhabi oilfields and at outcrops in Oman. Available data for oxygen and carbon isotope compositions, fluid inclusion measurements, cement abundance and formation water composition are interpreted in terms of a paragenetic model for the Thamama-B in field F in Abu Dhabi where the interval is deeply buried. The present synthesis provides a useful basis for understanding and predicting reservoir quality in static models and undrilled prospects, as well as for planning promising directions for further research. The goals of this study were to summarize the geologic setting and petrology of the Thamama-B reservoir and its surrounding dense zones, and to examine how sedimentology, stratigraphy and diagenesis have interacted to control porosity and permeability. Results that may have useful applications for similar microporous limestone reservoirs in general include:

We report the results of organic geochemical analyses of 19 crude oil samples from reservoir sandstones in the 4th Member of the Eocene Shahejie Formation from wells in the Minfeng Sag, Dongying Depression, Bohai Bay Basin (NE China). In addition, 42 Shahejie Formation core samples of dark-coloured mudstones, including 28 extracts, were analysed. Geochemical data included Rock-Eval measurements, gas chromatography, GC-MS and diamondoid analyses.

Maceral analyses showed that mudstones in the 4th Member of the Shahejie Formation (“Es₄”) contain Types I and II₁ kerogen. The member can be divided into upper (Es₄s) and lower (Es₄x) intervals. Oil-prone Es₄s rock samples have good to excellent hydrocarbon-generating potential based on calculated initial TOC values; Rock-Eval T_max values indicate that they are sufficiently mature for hydrocarbon generation. Analytical results suggest that both Es₄s and Es₄x mudrocks are potential source rocks for oils produced at fields in the Minfeng Sag.

Analysed crude oils from the Minfeng Sag were classified into three genetic groups. Group I oils are mature to highly mature and have undergone a moderate degree of thermal cracking. They are characterized by a low β-carotane/nC₂₅ ratio and C₃₀ 4-methylsterane index (4MI); high values of oleanane index (oleanane /C₃₀-hopane), C₂₇ diasterane/C₂₇ regular sterane (C₂₇Dia/C₂₇), regular sterane/17α hopane and gammacerane/C₃₀ hopane (G/H); and medium pristane/phytane ratios (Pr/Ph). This suggests that Group I oils are mostly derived from source rocks in the upper part of the Es₄x unit which are interbedded with evaporites. Group II oils are mature and have high 4MI and Pr/Ph ratios, low oleanane index, regular sterane/17α hopane and C₂₇Dia/C₂₇ ratios, and mediumβ-carotane/nC₂₅ and G/H. These features are similar to those of Es₄s source rocks, indicating their genetic correlation. Group III oils show the lowest maturity and highβ-carotane/nC₂₅ and regular sterane/17α hopane, and low oleanane index, Pr/Ph and 4MI. Previously-published data indicates that oils similar to those in Group III were mainly sourced by Es₄s mudstones.

A geochemical study was carried out on oil and gas samples from the Verkhnechonskoye field, located on the Nepa-Botuoba Anteclise in the central-southern part of the Siberian Platform. The goal of the study was to distinguish between fluids derived from the V_10-13 and B₁₂ reservoir units in the Vendian (Neoproterozoic) Katanga and Nepa Formations and to identify the producing reservoir using geochemical data. The results of analyses of 12 oil and 13 associated gas samples from the two reservoirs showed that all the fluids have similar geochemical properties including: low Pr/Ph ratios (0.78-1.00); a predominance of C₂₉ over C₂₇ and C₂₈ steranes; a predominance of odd-numbered C₂₁-C₂₅ n-alkylbenzenes over their even-numbered homologues; the presence of 12- and 13-methylalkanes; and a high relative abundance of tricyclic terpanes (cheilantanes). All these properties are consistent with those of the properties of petroleum from other fields on the Siberian Platform. The molecular and stable carbon isotope compositions of the oils and gases suggest that they were derived from marine organic matter with a high algal input deposited under reducing conditions. To date, specific source rocks which generated the oil and gas present at fields on the Nepa-Botuaoba Anteclise have not conclusively been identified, but potential candidates include the Upper Riphean Iremeken and Ayan Formations and more probably the Vendian Zherbinskaya, Seralakh, Vanavara and Nepa Formations.

The second part of the study demonstrates the application to reservoir geochemistry of C_3- and C_4- alkylbenzene compounds together with more conventional biomarkers. Key parameters were selected using statistical processing and displayed in graphic profiles. These profiles allowed the oil and gas samples to be classified according to the reservoir from which they were derived based on their geochemical properties. Parameters based on C_3- and C_4- alkylbenzene compounds were most effective in discriminating between oils from the two reservoirs. In addition, a new parameter is proposed based on the contents of 1-methyl-3-isopropylbenzene, 1-methyl-2-isopropylbenzene and 1-methyl-2-propylbenzene; this parameter correlates closely with the pristane/phytane ratio and can be used as an additional indicator of the level of oxicity in the source rock depositional environment.