Journal of Petroleum Geology最新文献

The Jurassic Shaximiao Formation in the southwest of the Western Sichuan Depression is an important tight gas reservoir. However, due to the strong heterogeneity of its reservoir properties and gas saturation, the factors influencing the differential enrichment of tight gas remain unclear. Based on logging, seismic, experimental, and drilling data, we have systematically studied the gas-bearing property characteristics, source rock characteristics, reservoir physical properties, fault characteristics, accumulation Period, and the factors controlling differential enrichment using the tight gas reservoir in the Yanjinggou area as a case. The study shows that the Shaximiao Formation is underlain by high-quality source rocks of the Xujiahe Formation (Upper Triassic) and capped by a regional seal of the Suining Formation (Jurassic). In the Yanjinggou area, anticline structures are well-developed, with sandbodies widely distributed and vertically stacked, and the overall reservoir is tight. The thickness and petrophysical properties of the reservoir display significant heterogeneity, which is controlled by the coupling of depositional and diagenetic processes. Gas layers are mainly found in channel sands trending NE-SW that exhibit superior reservoir properties. The fault–sand transport system is a crucial pathway for gas charging, migration, and accumulation, with structural highs and “V” shaped fault–sand configurations controlling the preferential enrichment zones. A tight gas accumulation model of “reservoir controlled enrichment, fault–sand controlled migration, and structural adjustment” was established. This model emphasizes that under the control of the fault–sand transport system, hydrocarbons initially migrate upward along faults into reservoirs that are separated from the source rocks, then laterally through the sandbodies. Favorable enrichment occurs in reservoir characterized by structural highs, good petrophysical properties, and greater thickness. The differential enrichment of tight gas in the Shaximiao Formation is controlled by a combination of factors, including the petrophysical properties and distribution of sandbodies and reservoirs, fault distribution, tectonic movement, and tectonically high positions. Comprehensive analysis indicates that the tight gas accumulation conditions in the Shaximiao Formation of the Yanjinggou area are favorable, providing a theoretical basis for predicting tight gas sweet spots in similar regions of the southwest of the Western Sichuan Depression.

The Akri-Bijeel area in the NW Zagros fold-and-thrust belt (Kurdistan region of northern Iraq) has been the focus of petroleum exploration, and its subsurface has been drilled extensively. This makes it possible to combine outcrop studies of this mountainous region with subsurface data. The region has five potential or regionally proven source rock units: the Ora Formation (Devonian–Carboniferous), the Baluti Formation (Upper Triassic), the Sargelu and Naokelekan Formations (Middle–Upper Jurassic), and the Chia Gara Formation (Upper Jurassic–Early Cretaceous). The area has a complex tectonic history, and it is therefore not necessarily clear when source rocks may have been active or inactive and therefore their generative potential. This makes basin modeling particularly useful as a tool to evaluate source rock thermal maturity and the timing of hydrocarbon generation and the amounts expelled. PetroMod version 2017 was used to reconstruct 1D burial and thermal history for four wells. The reconstructed burial and thermal history models were then calibrated against porosity, pressure, temperature, and vitrinite reflectance data. The results of constrained models show significant variations in heat flow through time, with high heat flows during Mesozoic rifting followed by low values, with sharp decreases in heat flow since the end of the Miocene. The present-day average geothermal gradient at Akri-Bijeel is low (18°C/km), with an average heat flow of 32 mW/m². The low heat flow can best be explained by the rapid deposition of a thick, cold Cenozoic sedimentary section, Zagros thrusting and accompanying uplift and exhumation, and the ongoing circulation of cold meteoric waters under hydrodynamic conditions. Thermal maturity modeling reveals that the present-day oil window extends from a depth of 860 m in well Bakrman-1 down to 5090 m in well Bijeel-1. The generation of hydrocarbons in the modeled source rocks (except for the Ora Formation) continued until it was halted by Zagros folding and thrusting in the Miocene, after which generation ceased or became negligible. Models predict that the majority of the oil discovered at Akri-Bijeel was generated by the Sargelu, Naokelekan, and Chia Gara Formations. On the basis of 1D basin modeling, the Paleozoic Ora Formation generated oil during the Early Triassic and is now in the gas window, and Jurassic source rocks generated oil during the Cretaceous. Volumetric calculations for the five source rock formations modeled in the area suggest that around 4.94 billion tons (or 36 billion barrels [bbl]) of petroleum have been expelled and charged to the reservoirs, indicating significant remaining potential for undiscovered resources.

Lower Permian organic-rich shales and coals from the Ib River sub-Basin, part of the Mahanadi Basin in Eastern India, were studied using Rock-Eval pyrolysis, kerogen kinetics, biomarker, and organic carbon isotopic analyses to investigate the source rock characteristics, depositional environment, and thermal degradation kinetics of the sedimentary organic matter (OM). The samples are organically rich (>5 wt% total organic carbon [TOC]) and possess higher hydrocarbon generation potential (>54 mgHC/g rock). The primary contributors to the OM supply were identified as terrestrial plants, supplemented by emergent aquatic plants, resulting in a Type II–III kerogen. The broader activation energy indicates OM input from heterogeneous sources, whereas the earlier and faster kerogen transformation ratio (TR), along with a high hydrocarbon generation rate (HGR), suggests excellent kerogen quality. Despite the samples’ favorable source rock characteristics, their relatively low T_max values (<435°C) indicate immaturity, limiting their potential for natural hydrocarbon production. Marine incursions have been identified in the Barakar Formation of the Ib River sub-Basin, accompanied by climatic fluctuations (inferred from P_aq, average chain length [ACL], and δ¹³C) that correspond to alternating dry and wet periods during the deposition of various lithotypes. The samples exhibit an abundance of even lower n-alkanes, indicating that the OM inputs are derived from aquatic vegetation rather than microbial activity. The gammacerane index (GI) averages ∼0.29 for the Barakar Formation and ∼0.24 for the Karharbari Formation, indicating greater water stratification and higher salinity in the Barakar Formation compared to the Karharbari Formation. Likewise, other key parameters such as tricyclic terpanes (TTs) and polyaromatic hydrocarbons (fluorenes [FLs], dibenzothiophenes [DBTs], and DBFs) differentiate certain Barakar samples as being deposited in a saline lacustrine environment, whereas the other Barakar samples and all Karharbari samples indicate a swampy, oxic environment. The pristane (Pr)/phytane (Ph) ratio supports this conclusion, indicating a reducing to oxidizing depositional setting for the Barakar Formation, while suggesting an oxic environment for the Karharbari Formation. Integrating all parameters, we conclude that the Barakar Formation was influenced by marine activities during Permian Period. Drawing on our research and prior studies, we propose two scenarios for marine interaction in the Ib River sub-Basin during the Permian Period: Either the region was covered by an extended marine embayment or marine influence extended to the NW-SE slope of the basin, notably affecting the Rewa region in the northwest.

Six oil samples from an Upper Devonian carbonate reservoir in the Orenburg field in the SE Volga-Ural Basin (Russia) were analyzed geochemically, together with extracts of five core samples of the Domanik Formation source rock (Frasnian-Tournaisian) from a well located in the south of the basin. Biomarker analyses of saturated and aromatic oil fractions were combined with new data on the molecular structure of asphaltene in order to investigate source rock organic matter input, depositional environment, and thermal maturity. The studied oil samples have high API values (31°–37°) and saturated hydrocarbon contents up to 66%, suggesting that they were generated by a thermally mature source rock and consistent with high contents of С₆–С₁₄ n-alkanes relative to C₁₅₊ of the oil-asphaltene fraction. The molecular structure of asphaltene derived from pyrolysis-gas chromatograpy-mass spectrometry (Py-GC-Ms) analyses also suggests that the oils were generated by a source rock containing marine Type II kerogen, consistent with the H/C atomic ratio up to 1.25. Bulk kinetic analyses of the asphaltene showed a relatively broad range of activation energies between 40 and 58 kcal/mol and a frequency factor (A) of 12E+14/1 s. The biomarker characteristics of aliphatic and aromatic fractions in the studied oils suggest that they were generated by carbonate-rich source rocks containing organic matter of marine algal origin deposited under anoxic conditions. Furthermore, maturity-sensitive biomarker parameters show that the oils were generated at peak oil window maturities. Oil-source rock correlations of biomarker proxies indicated that the analyzed oils from the Orenburg field were mainly generated by carbonate-rich shaley source rocks in the Domanik Formation.

This study examines the bulk organic geochemical properties, the burial and thermal history reconstruction, and timing of hydrocarbon generation of Jurassic and Cretaceous source rocks in the Abadan Plain, within the western Zagros fold-and-thrust belt in SW Iran. Three source rock units were evaluated: the Middle Jurassic (Bajocian–Callovian) Sargelu Formation, the Lower Cretaceous (Neocomian) Garau Formation, and the Lower Cretaceous (Aptian–Albian) Kazhdumi Formation. Rock-Eval pyrolysis and organic petrography analyses revealed that the Sargelu Formation is overmature, with abundant solid bitumen and pyrobitumen, indicating depleted hydrocarbon generation potential. Total organic carbon (TOC) values range from 0.46 to 14.8 wt% with low hydrogen index (HI) values, suggesting no further liquid hydrocarbon generation is possible. The Garau Formation is highly mature with TOC values of 0.44–9.4 wt% and HI values below 400 mg HC/g TOC, confirming that hydrocarbon generation has occurred. While the advanced maturity of both formations prevents direct kerogen-type identification through Rock-Eval results, petrography indicates the Sargelu and Garau formations are indicative of Type II kerogen. The Kazhdumi Formation shows varied maturity levels, ranging from immature to marginally mature, with TOC values between 0.16 and 6.33 wt% and HI values from 72 to 626 mg HC/g TOC, reflecting a mix of Types II and III kerogen.

The one-/two-dimensional basin modeling conducted across the Azadegan, Yadavaran, Darquain, and Mahshahr fields reveals significant variations in burial depth, thermal history, and hydrocarbon generation potential. Thermal modeling indicates maximum burial temperatures were reached in the late Neogene, with the basal heat flow value of 45 mW/m² for most fields, except in Darquain, where an elevated basal heat flow of 62 mW/m², potentially linked to detachment thrusting within the Hormuz salt caused by the reactivation of basement faults, accelerated thermal maturation of the Sargelu and Garau source rocks. In Darquain, the Sargelu Formation has entered the wet gas window (VRo% ∼1.9), and the Garau Formation. has reached late oil to wet gas maturity (VRo% ∼1.5), while in Azadegan both remain in the late oil window. The Kazhdumi Formation remains immature to marginally mature across all fields. The calculated transformation ratio (TR) shows that the Sargelu and Garau Formation. Source rocks in Darquain have surpassed 90% TR, fully exhausting their liquid hydrocarbon generation potential. These findings offer critical insights into the petroleum system of the Abadan Plain, highlighting areas like Darquain, where hydrocarbons have already been expelled and zones such as Azadegan and Mahshahr, with further oil generation potential.

Core- and well log-based techniques of reservoir characterization were used to independently assess mid-Cretaceous (Albian–Santonian) flow units in the Bangestan Group reservoir of the Mansuri oilfield, located in the Dezful Embayment of SW Iran. The outcomes of the two techniques were compared to assess their utility in flow unit determination. Core-based reservoir classification using the “Flow Zone Indicator” and “Stratigraphic Modified Lorenz Plot” approaches defined 15 flow units in the Mansuri reservoir, including three speed zones. Well log-based (“K-means” and “linkage clustering”) methodologies provided broadly consistent results with 16 flow units defined in the same reservoir sequence. The log-based reservoir zonation gave a better vertical and laterally continuous representation of the reservoir geometry, while the core-based zonation provided more information about reservoir quality and ranking of the flow units identified. To assess its regional significance, a reservoir zonation combining both techniques was then compared with Bangestan Group reservoirs across SW Iran. The analysis highlighted the influence of regional unconformities and associated subaerial exposure upon reservoir quality and flow unit geometries within the Bangestan reservoir. These exposure surfaces had distinct well log signatures, which could be traced across the region and used to define the regional configuration of the Bangestan Group reservoir in the absence of core data.

Benzocarbazole (BC) migration tracers were used to investigate the complex filling of reservoir segments at the Solveig field in the Norwegian North Sea. The study suggests that the benzocarbazole ratio [a]/([a]+[c]) of crude oils and extracts decreases with inferred increasing migration distance. The complex filling history of the Solveig field is evident from the observation of variable degrees of palaeo biodegradation associated with two palaeo oil-water contacts in residual oil zones below non- to moderately biodegraded live oil columns. Live oil properties also vary significantly across the field. Benzocarbazole ratios (BCRs) obtained from oils and reservoir core extracts appear not to be affected by biodegradation and indicate a migration and filling trend from NW to SE. The BCR values were set by the initial phase of filling and do not show any overprint effects as a result of later and more mature oil charges.

BCRs from both oils and extracts of reservoir cores, particularly those composed of clean sands, helped to reconstruct migration processes in the Solveig field. Migration is construed to have first filled reservoir segment D in the NW of the field and to have continued further east towards segment C, and then via segment B and finally into segment A. Migration then continued along the southern margin of the Haugaland High to a well location to the east of the Solveig field. A fractionation effect for benzocarbazoles derived from oils versus those from extracts was noted and was attributed to differential partitioning behavior. Nevertheless, spatial trends for oil- and extract-derived BCRs were congruent. This allowed the generation of spatially more highly-resolved benzocarbazole datasets for migration assessment by combining data from both samples types (oil and reservoir extracts) if partitioning is accounted for.