Journal of Petroleum Geology最新文献

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.

The Cenozoic stratigraphy of the Zagros records the ongoing collision between the Arabian and Eurasian Plates and the closure of NeoTethys. A Paleogene NW-SE trending foreland basin was inherited from a Late Cretaceous precursor. Widespread progradation into the foredeep was a feature of both margins which, allied to ongoing tectonism, had by the late Eocene led to the narrowing and subsequent division of the foredeep into the Lurestan – Khuzestan and Lengeh Troughs, separated by the northward continuation of the rejuvenated Qatar-Fars Arch. This sub-division strongly influenced subsequent deposition and the petroleum geology of the area. In addition, the diachronous nature of the Arabian – Eurasian collision led to strong diachroneity in lithostratigraphic units along the length of the Zagros. Hence its petroleum geology is best understood within a regional sequence stratigraphic framework. This study identifies three tectono-megasequences (TMS 10, TMS 11a, TMS 11b) and multiple depositional sequences.

The Cenozoic contains a world class hydrocarbon province with prolific oil reservoirs in the Oligo-Miocene Asmari Formation sealed by the evaporite-dominated Gachsaran Formation, mostly contained within giant NW-SE trending “whaleback” anticlines concentrated in the Dezful Embayment. Reservoirs in the SW are dominantly siliciclastic or comprise mixed siliciclastics and carbonates, whereas those to the east and NE are dominated by fractured carbonates. There remains untested potential in stratigraphic traps, especially in deeperwater sandstone reservoirs deposited along the SW margin of the foredeep.

Late Miocene to Pliocene charge to the Asmari reservoirs was mostly from Aptian – Albian Kazhdumi Formation source rocks. In some fields, an additional component was from organic-rich late Eocene to earliest Oligocene Pabdeh Formation source rocks confined to the narrowing Lurestan – Khuzestan Trough. Where mature, the latter source rock is also a potential unconventional reservoir target, although the prospective area is limited due to recent uplift and erosion. Deeper Jurassic source rocks contributed to the Cheshmeh Khush field in Dezful North. Silurian source rocks charged gas-bearing structures in the Bandar Abbas region.

The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid-Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra-, inter- and sub-salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses.

Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra- and inter-salt reservoir rocks; the oils are early mature, enriched in heavy (C₃₆₊) hydrocarbons, heteroatoms, aryl-isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub-salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C₂₇ regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter-salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions.

Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate-rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM-rich marine shales of Frasnian age or older.

The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil-oil and oil- source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil- source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter-salt succession and marine shales and/or carbonates in the sub-salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Fr

The Arabia – Eurasia collision zone in the central part of the Alpine – Himalayan orogenic system has had a complex deformation history since the Palaeozoic. In Iran, the collision zone consists of the Alborz-Talesh, Kopeh Dagh and Zagros foldbelts and the intervening Central Iran area. In this review paper, we summarize the structural architecture and tectonostratigraphic characteristics of these domains and attempt to correlate regional deformation events between them. The results show that six regional-scale deformation phases can be recognized and correlated in Iran over a time interval extending from the Late Palaeozoic to the Late Cenozoic.

Late Palaeozoic rifting in northern Gondwana and subsequent oceanic spreading resulted in the separation of the Central and North Iran blocks from the Arabian Platform. These blocks later converged and collided with the southern margin of Eurasia due to the subduction of the intervening PalaeoTethys lithosphere (“Cimmerian orogeny”: Late Triassic). The convergent setting resulted in the initial development of the Alborz-Talesh foldbelt in present-day northern Iran, while extensional basins developed in the forebulge area in Central Iran. Continuing northward subduction of NeoTethyan oceanic lithosphere at the southern Eurasia margin produced Early Cretaceous back-arc extension and associated volcanism in Central Iran and the Alborz-Talesh area to the north. A phase of compressional deformation in the Late Cretaceous was related to the collision of a series of microcontinents derived from Northern Gondwana, including the Ercinjan and Bitlis massifs, with the Central Iran block, and is recorded in the Alborz-Talesh foldbelt and in Central Iran. Further back-arc extension in the late Paleocene – Eocene was accompanied by pervasive volcanism and volcaniclastic sedimentation throughout northern and Central Iran. The final closure of NeoTethys and convergence between the Arabian and Eurasian Plates evolved through phases of early Oligocene “soft” collision and middle Miocene “hard” collision. This was accompanied by thrusting in the internal parts of the Zagros foldbelt and by folding and subordinate thrusting in the more external parts, with related development of the flexural Mesopotamian Basin in the foreland to the SW.

Petroleum accumulations may coincide with either positive or negative temperature anomalies, which are conventionally detected using in situ temperature measurements made in shallow boreholes 1-3 m deep. Data gathered in this way, however, can be sparse and costly, and may require intensive fieldwork over a long time period. This article explores the possibility of detecting thermal anomalies associated with petroleum entrapment using satellite-derived land surface temperature data. For this aim, a robust correction scheme based on a physically-based land surface model was applied to night-time kinetic temperature data derived from NASA's ASTER instrument. The numerical model, known as SKinTES, attempts to simulate diurnal effects and to remove them from the measured temperature data to yield a residual temperature anomaly map. The performance of this methodology was tested over the Alborz oilfield located on an anticline of the same name in the Qom region of Central Iran. The study area has an arid to semi-arid climate and the surface geology is dominated by outcrops of the Lower Miocene Upper Red Formation. The modelling approach used successfully highlighted several negative temperature anomalies over the oil-bearing parts of the Alborz structure. In comparison to the uncorrected data, the anomalies were shown to be highly enhanced in both spatial and magnitude terms. In addition, time series analysis indicated that the temperature anomalies were consistent over time. The authenticity of the anomalies was confirmed by a suite of in situ temperature measurements made at shallow boreholes. In conclusion, a unifying framework is proposed to explain the occurrence of both negative and positive temperature anomalies over petroleum accumulations. The new modelling and correction scheme is expected to broaden the application of remote sensing land surface temperature data not only in petroleum exploration but also in other types of geothermic investigations including geothermal exploration.