Distribution Of Source Rocks Research Articles

Characteristic of source rocks and origin of crude oils in the Raoyang Sag and Baxian Sag, Bohai Bay Basin, China: Insights from geochemical and geological analyses

Three potential source rock intervals were evaluated based on the results of Rock-Eval pyrolysis on nearly 700 rock samples and the origin of the twenty-two oil-fields was studied by the biomarker analysis on 62 source rock samples and 93 oil samples in the Raoyang Sag and Baxian Sag, Bohai Bay Basin. The first member of the Shahejie Formation (Es) was deposited in an anoxic and salted water column with the dominant contribution of algal organic matters, reflected by its rock samples with high gammacerane/C30-hopane, high ETR, high C35/C34 hopane, high steranes/hopanes, low pristane/phytane, low C27-diasterane/C27-sterane and low C19/C23 tricyclic terpane. Characterized by higher C19/C23 tricyclic terpane, higher pristane/phytane, lower steranes/hopanes and lower C35/C34 hopane than the Es1 rock samples, the biomarkers of rocks suggest that the third and forth members of the Es were deposited in the sub-oxic to anoxic environments with a significant terrestrial organism input. Further studies suggest that the best source rock interval for oil-generation is the Es1 source rock interval in the Raoyang Sag and is the Es3 source rock interval in the Baxian Sag by organic facies analysis of source rocks. Three source-related oil groups have been identified. There are two oil groups for the discovered oils in the Raoyang Sag. Group I oil, dominated by the Es1-derived oils, has been found in all the oil-fields in the Raoyang Sag, and Group II oil, mainly derived from the Es3 source rock interval, only distributes in the north-east area and in the south end of the Raoyang Sag. However, the three oil groups have been found in the Baxian Sag, but the Es3-derived oils are dominant in them and have been found in the major oil-fields in the east area and the Wen'an slope in the west area. Furthermore, the Es4-derived oils (Group III oil) mainly distribute in the Baxian Sag, without any findings in the Raoyang Sag because of the absence of the Es4 source rocks. As our studies, oils almost accumulate near their source rocks without a long-distance migration except the slope areas in the Raoyang Sag and Baxian Sag. Therefore, the source rock distribution is a key factor to oil accumulations in the Raoyang Sag and Baxian Sag, especially the efficient source rock distributions, which mainly developed in the organic facies A and B based on the geochemical and geological researches.

Relationship between source rock development and petroleum accumulation in the Erlian Basin, northern China

AbstractThe Wuli and Saihan sags in the Erlian Basin, the most petroliferous basin in northern China, were analysed with bulk geochemical analysis, carbon isotopic composition, microthermometry of fluid inclusions, and basin modelling to characterize the organic matter abundance and composition, to construct source rock development models, and to reveal the relationship between source rock development and hydrocarbon accumulation. The samples display wide variations in total organic carbon content and Rock‐Eval indices, suggesting heterogeneity of organic matter richness and type. The Wuli Sag has oxic depositional environment, high productivity, and high total organic carbon content; the effective oil source rocks are mainly distributed in the deep sag where the productivity is high; and there is plenty of organic matter left and preserved after degradation. In the Saihan Sag, there is a small amount of organic matter deposited because of low productivity; the effective oil source rocks are mainly distributed in the slope by the deep sag where the reducing degree is the strongest. The source rock development models controlled the geochemical characteristics and distribution of source rocks, which are the keys to hydrocarbon potential and accumulation. The oil of Wuli Sag is mainly distributed in the deep sag, whereas the oil of Saihan Sag is mainly distributed in the slope by deep sag, which is in agreement with the previously effective oil source rocks distribution. In the strong division sags, the region where source rock distributed is beneficial to hydrocarbon accumulation. The conclusions may have important implications for petroleum exploration in other small lacustrine depositional systems.

Controls on minibasin infill in the Nordkapp Basin: Evidence of complex Triassic synsedimentary deposition influenced by salt tectonics

The Nordkapp Basin is a northeast-trending upper Paleozoic rift basin located in the western Barents Sea. The presence of salt structures makes this basin of interest for hydrocarbon exploration. Nevertheless, no commercial discoveries have been made so far, and the basin remains poorly understood in terms of distribution of reservoirs and source rocks within its salt minibasins. In this study, a three-dimensional data set together with well data in a small area located in the southwestern subbasin of the Nordkapp Basin has been studied, with the main purpose of obtaining a better understanding of salt kinematics and minibasin infill, with special focus on the Triassic. The minibasin infill of the Nordkapp Basin has been subdivided into five second-order sequences, which mark the main regional events recorded in the Barents Sea. Further subdivision into third-order sequences has been made in the Triassic in response to the local halokinetic movements of the basin. In terms of salt kinematics, the Nordkapp minibasins have been affected by the following: (1) late Permian–Early Triassic minor salt mobilization, (2) latest Early Triassic reactive diapirism, (3) Early to Middle Triassic transition between reactive–passive diapirism, (4) Middle Triassic–Jurassic passive diapirism, (5) Late Jurassic–Early Cretaceous gravity gliding, and (6) Cenozoic regional contraction. The rapid changes in depositional environment observed in well 7228/7-1A, together with the large variability of seismic responses and reflection terminations, provide evidence of a complex Triassic paleogeography controlled by salt tectonics. Early to Middle Triassic differential loading of minibasins into the underlying salt formed broad diapir-induced highs, which might have acted as local sources of sediment for submarine debris flows and fan deltas developed adjacent to salt structures. During the Middle Triassic–Jurassic last stage of passive growth, salt diapirs formed local topographic highs covered by ephemeral roofs and caused narrow areas of deformation widths less than 1 km (3281 ft), developing composite halokinetic sequences. In minibasins, salt evacuations and associated subsidence controlled the spatial transgressive–regressive trends of fluviodeltaic systems coming from the southeast of the Barents Shelf. Rapidly subsiding minibasins were flooded by marine conditions, and intervals of organic-rich source rocks might have been deposited in salt withdrawal-related depressions. As subsidence decreased, newly developed regressive sequences of northwest-trending fluviodeltaic systems sourced from the southeast covered previous marine environments, possibly depositing potential fluviodeltaic reservoirs within the salt minibasins.

Hydrocarbon Generation Potential of the Upper Palaeozoic Coal Measure Source Rocks in Su11 Block

Based on the analysis of regional geological background, relevant work is carried out through experimental testing, logging evaluation, and reservoir forming characteristics analysis and drilling productivity statistics. The analysis shows that the residual organic carbon content of the Upper Paleozoic coal measure source rocks in the Su 11 block ranges from 40.86% to 70.75%, and the residual organic carbon content of the dark mudstone ranges from 0.51% to 26.80%. The organic matter is mainly composed of vitrinite and inordinate with carbon isotope ranging from -24.81 ‰ to 22.64 ‰ and type 3. The vitrinite reflectance distribution of source rocks is between 1.2% and 2.1%, and is in the mature-high maturity stage. The total gas generation intensity of source rocks is between (10-50) × 108m3 and km2. The plane shows “strong north weak” Tight sandstone gas migrates into the reservoir through “near source”, and the gas source conditions have significant control over the gas reservoir distribution.

PETROLEUM PROVINCES OF THE PARATETHYAN REGION

Initial crustal collision between Africa and Eurasia in the middle Eocene – early Oligocene enclosed a semi‐restricted Paratethyan seaway of linked basins and platforms across a region stretching from the Eastern Alps to the South Caspian Sea. As the African Plate continued to advance north during the later Neogene, the seaway shrank into a series of more isolated basins separated by the rising Alpine – Carpathian – Caucasus fold‐thrust belts. Organic‐rich oil‐prone Paratethyan source rocks of middle Eocene (Kuma Formation and equivalents) and Oligocene – early Miocene (Maikop and Menilite Beds) ages, and more gas‐prone post‐orogenic mid‐upper Miocene shales, subsequently charged over 2500 accumulations across the region with combined recoverable reserves of 95 billion brl oil‐equivalent (B boe). These accumulations are clustered in discrete petroleum provinces, each with a distinct tectono‐stratigraphic architecture and comprised of one or more petroleum systems. The provinces can be grouped into five broad categories: Average Reserves Average Field Sizes Fold‐thrust Provinces 60,980 MMboe 2–590 MMboe Sub‐thrust Provinces 255 MMboe 3.4 MMboe Foreland Provinces 18,671 MMboe 2–77 MMboe Intermontane Provinces 13,122 MMboe 1–40 MMboe Black Sea back‐arc Province > 1391 MMboe >33 MMboe The productivity of each province (estimated very approximately from the number of barrels oil equivalent / square kilometre) is extremely variable, and its relationship with the geological factors controlling hydrocarbon entrapment and retention is complex. The most critical of these factors appears to be the quality and distribution of source rocks and post‐charge structural modification.

Source and seal coupling mechanism for shale gas enrichment in upper Ordovician Wufeng Formation - Lower Silurian Longmaxi Formation in Sichuan Basin and its periphery

Abstract In recent years, theoretical geologic research has made important progress in shale gas exploration and development, and new discoveries, such as the Jiaoshiba, Weiyuan and Changning shale gas fields, provide geological cases to define key controls on shale gas accumulation in Wufeng Formation-Longmaxi Formation marine shale strata. A mechanism coupling source and seal development for shale gas enrichment is proposed in this study based on detailed research results of isochronous stratigraphic distribution of source rock and seals and source-seal dynamic evolution. Great thickness, wide distribution and high total organic carbon content (TOC) of sources are key controls on the shale gas content, and storage capacity in organic matter-hosted pores, micro-cracks and bedding fissures is intensively developed. The Wufeng Formation and the lower part of the first member of the Longmaxi Formation (WF2-LM4 graptolitic zone) are favorable sources that feature a slow deposition rate, well graptolitic zone, favorable organic organism type and high TOC. The organic matter type is benefit to the development of organic-matter pores because the planktonic algae tends to generate and expulse large amounts of hydrocarbon and form many organic-matter pores. Both high biogenic quartz and high TOC ensure development of abundant organic matter-hosted pores and result in a three-dimensional network of interconnected organic matter pores that allows shale gas storage and flow. The seal can be divided into direct and indirect seals. The direct seal refers to the middle and upper parts of the first member of the Longmaxi Formation (LM5 and higher graptolitic zone) that are characterized by low TOC and low porosity. The indirect seal refers to the regionally distributed Lower-Middle Triassic gypsum layer(s) and mudstone that maintain regional geopressure systems. The shale gas fields of Jiaoshiba, Fushun-Yongchuan and Changning have high geopressure coefficient factors (1.5, 2.0 and 1.5, respectively). In the absence of the Lower-Middle Triassic gypsum layer(s) and mudstone regional seals, the high-pressure system was destroyed and resulted in low-normal geopressure shale gas reservoirs, for instance, the Pengshui and Zhaotong wells. The static match and dynamic match of source and seal constrain the location of shale gas reservoirs and the degree of shale gas enrichment. The model of a mechanism coupling source and seal for shale gas enrichment provides new ideas and methods for the assessment of shale gas. This model promotes the evaluation of shale gas from the static parameters approach to the source and seal dynamic approach. In the Sichuan Basin and its peripheral areas, the promising areas for shale gas accumulation are those with favorable sources in the WF2-LM4 graptolitic zone and the presence of the Lower-Middle Triassic gypsum layer(s) and mudstone regional seal.

Families of reservoired crude oils from the Cangdong Sag, Bohai Bay Basin, China

The organic geochemistry of 35 crude oils from six oil fields across the Cangdong Sag, Bohai Bay Basin, was characterized and an oil family classification was carried out for the first time. Four oil families were classified based on 18 parameters related to source and depositional environment using hierarchical cluster analysis. The families have broadly similar geochemical characteristics which suggest oils derived from lacustrine source rocks deposited in a reducing environment. Family A has relatively abundant C27 steranes and C30 4α-methyl-24-ethylcholestanes, high Pr/Ph, C22/C21 tricyclic terpane and C31R/C30 hopane ratios, and low ETR, C26/C25 tricyclic terpane and C35S/C34S homohopane ratios. Family A shows higher thermal maturity than families C and D, but lower than family B. The most distinct feature for Family B is the high gammacerane index; they also show slightly higher C22/C21 tricyclic terpane, C31R/C30 hopane and C29/C30 hopane, lower dibenzothiophene/phenanthrene, and higher maturity than the other families. Families C and D oils are low maturity and they are more similar to each other than families A and B based on most biomarker ratios. However, family C can be distinguished from family D by slightly higher C27/C29 steranes and C30 4Me/C29 steranes C30 4α-methyl-24-ethylcholestanes/C29 steranes, and lower C29 steranes/C30 hopane ratios. A preliminary oil–source rock correlation suggests that the oil families originated from various intervals having different organofacies within the second member of the Kongdian Formation. Family A is more widespread than the other families, supporting extensive distribution of the source rock. Family B was only found in the southern part of Kongdong slope, which suggests limited geographical distribution of the related source rock. Families C and D show similar geographical distributions and dominate Wangguantun, Shenjiapu and Shenvsi fields, suggesting that the source kitchens are near these regions.

Neoproterozoic stratigraphic framework of the Tarim Craton in NW China: Implications for rift evolution

The Tarim Craton is overlain by thick Neoproterozoic sedimentary successions in rift tectonic setting. This study examines the latest outcrop, seismic, and drilling core data with the objective of investigating the regional stratigraphy to deeply recognize the evolution of rifting in the craton. Cryogenian to Lower Ediacaran successions are mainly composed of clastic rocks with thicknesses of 2000–3000 m, and the Upper Ediacaran successions are composed of carbonate rocks with thicknesses of 500–800 m. The rift basins and stratigraphic zones are divided into northern and southern parts by a central paleo-uplift. The northern rift basin extends through the northern Tarim Craton in an E–W direction with two depocenters (Aksu and Kuruktag). The southern rift basin is oriented NE–SW. There are three or four phases of tillites in the northern zone, while there are two in the southern zone. Given the north–south difference of the stratigraphic framework, the northern rift basin initiated at ca. 740 Ma and the southern rift basin initiated at ca. 780 Ma. During the Cryogenian and Ediacaran, the northern and southern rift basins were separated by the central paleo-uplift, finally connecting with each other in the early Cambrian. Tectonic deformation in the Late Ediacaran led to the formation of a parallel unconformity in the rift basins and an angular unconformity in the central paleo-uplift. The Neoproterozoic rift basins continued to affect the distribution of Lower Cambrian hydrocarbon source rocks. The north–south distribution and evolution of the rift basins in the Tarim Craton have implications for reconstructions of the Rodinia supercontinent.

Evolution of the Neoproterozoic rift basins and its implication for oil and gas exploration in the Tarim Basin

According to the aeromagnetic, seismic, and geological data, the surface structure, sedimentation, and distribution characteristics as well as the deep dynamic mechanism of the north-south differentiated Neoproterozoic rift basins were well investigated to reveal the tectonic evolution and its control on the distribution of the Early Cambrian sedimentary basin and source rocks in the Tarim Basin. The rift basin in the southern Tarim was a product of superplume activities during the early breakup period of the Rodinia supercontinent. It initiated in the Early Cryogenian (about 780 Ma) and appeared as NE-direction aulacogens extending into the Tarim Basin. The rift basin in the northern Tarim was a back-arc rift basin derived from the subduction of Pan-Rodinian oceanic plate, which initiated in the Late Cryogenian (about 740 Ma) and occurred as a nearly EW-direction narrow band across the Tarim Basin. The northern Tarim back-arc rift basin had similar formation and evolution process to the Late Mesozoic-Cenozoic back-arc rift basins in East Asia, both showing an oceanward migration; however, the Tarim rift basin finally evolved from the fault-depression basins into passive continental margin. The Neoproterozoic rift basins controlled not only the distribution of source rocks in the syn-rift period but also the development of Early Cambrian sedimentary basin. Nearly EW-distributed syn-rift (Cryogenian to Ediacaran) and post-rift (Lower Cambrian Yurtusi period) source rocks were likely to develop between the present Tabei uplift and central uplift belt.

Palaeoenvironmental reconstruction of lacustrine source rocks in the lower 1st Member of the Shahejie Formation in the Raoyang Sag and the Baxian Sag, Bohai Bay Basin, eastern China

The lower 1st Member (Es1L) of the Oligocene Shahejie Formation is the most important source rock interval in the Raoyang Sag and the Baxian Sag. To reveal the controlling factors that affected the distribution of organic-rich source rocks, we analyzed the lower Es1 (Es1L) samples collected from the Raoyang Sag and the Baxian Sag using sedimentological and geochemical techniques to reconstruct the lacustrine palaeoenvironmental conditions. Most of the samples had chemical index of alteration (CIA⁎) values between 70 and 75, which reflect a stable and moderately weathered source under a transitional climate. The distribution of depocenters and palaeo-water depths indicated that the main catchment area was concentrated in the Raoyang Sag, with a maximum palaeo-water depth of 14m and a wave-base depth of 7.5m. Stable isotope data from carbonates (δ18Ocarb and δ13Ccarb) showed that the lakes with long residence times in the Raoyang Sag had a positive correlation and that the lakes with short residence times in the Baxian Sag had no isotopic covariance during the deposition of the lower Es1. The P/Al and P/Ti ratios, Ptotal and carbon isotope values of the organic matter (δ13Corg) in the two sags illustrated stable palaeoproductivity without much fluctuation. The enrichments of Mo, U and ratios of (C:P)org, B/Ga and Sr/Ba further indicated saline and anoxic bottom water conditions associated with stable water-column stratification in Well Xi63 and brackish and less anoxic bottom water conditions in Well ND1 during the deposition of the main source rock of the lower Es1. Moreover, the plots of Mo and U enrichment versus TOC and hydrogen index values versus Δδ13C (i.e., the difference between the δ13C values of carbonates and organic matter) corroborated the inference that the preservation of organic matter was the main factor controlling the formation of organic-rich source rocks in the Raoyang Sag and the Baxian Sag during the deposition of the lower Es1.

Petroleum geology of the 2018 offshore acreage release areas

A total of 21 areas were released in 2018 for offshore petroleum exploration. They are located in the Bonaparte, Browse, Northern Carnarvon, Bight, Otway and Gippsland basins. All release areas were supported by industry nominations, indicating that interest in exploring Australia’s offshore basins remains strong, despite the significant decrease in the number of exploration wells drilled in recent years. Sixteen areas are being released under the work program bidding system with two rounds, one closing on 18 October 2018 and the other on 21 March 2019. Five areas are being released for cash bidding and include the producible La Bella gas accumulation in the Otway Basin. Prequalification for participation in the cash-bid auction closes on 4 October 2018 with the auction scheduled for 7 February 2019. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. The regional evaluation of the petroleum systems in the Browse Basin has been completed and work continues on assessing the distribution of Early Triassic source rocks and related petroleum occurrences across the North West Shelf. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, are made available through the National Offshore Petroleum Information Management System. Additional datasets are accessible through Geoscience Australia’s data repository.

The strata and palaeo-geomorphology framework at the end of neoproterozoic and development mode of source rocks at the beginning of Cambrian in Tarim Basin, China

Referred to the new recognition from petroleum exploration of the Sinian to Cambrian in South China, it could be considered that the distribution of the early Cambrian source rocks was controlled by the palaeo-geomorphology at the end of Neoproterozoic in the Tarim Basin. Based on the zircon U-Pb dating of pyroclastic rock samples from the clastic rock stratum under the bottom of Cambrian carbonate rocks, the stratigraphic correlation of the Sinian to Cambrian was conducted to build the palaeo-geomorphology framework at the end of Neoproterozoic in Tarim Basin. Lastly, according to the development mode of source rocks at the beginning of Cambrian, the distribution of source rocks was predicted initially through the division of seismic facies. The youngest zircon concordia age of pyroclastic rocks from the bottom of well Tong 1 is 707±8Ma. It was revealed by the strata framework of the Sinian to Cambrian, the palaeo-geomorphology at the end of Neoproterozoic in Tarim Basin was characterized by an uplift highland in Bachu-Tazhong area, the south north high-low, and the west is higher than the east. The distribution of source rocks in the bottom of the Cambrian on the palaeo-platform and slopes was coincident with the Upper Sinian dolomite basically. But the contemporaneous sediment happened to be absent or changed in sedimentary facies on the uplift and its edges. From the seismic facies of the strata under the bottom of Cambrian, it could be concluded that source rocks in the type of the Xishanbraque Group (∈1xs) was limited in the Manjiaer Depression, while the source rocks in the type of the Yuertusi Group (∈1y) are widely distributed in south of Tabei Uplift, east Awat Depression, and even the Maigt Slope. However, among the west Awat Depression and western Tanguzibasi Depression, and the middle area of the Bachu-Tazhong Uplifts, the contemporaneous source rocks may have changed into sedimentary facies of tidal flat and lagoon, instead of deep shelf.

Wave processes in relation to the tectono-sedimentary of the Tarim basin: A new method for basin study

This study gives insights into the tectonic and sedimentary evolution of the Tarim basin, the largest petroleum-bearing basin in Western China, by analyzing sedimentary wave process using multi-scale decomposition of the wavelet transform method, and the mathematical defects of sliding-window method in the process of sedimentary wave analysis was discussed. The filtering analysis, in the time domain, was carried out on cores collected from 14 wells in the Tarim basin. The results show that the evolution of the Tarim basin was controlled by various wave processes. The periods of 212 ± Ma, 102 ± Ma and 33 ± Ma indicated a strong sedimentary rhythm, which displayed a spatial and temporal evolution of wave characteristics. The 33 ± Ma period represented a third-order sequence of the stratigraphic division, which identified with the unconformities of the Tarim basin; 102 ± Ma period corresponded to an important period of sedimentation and the plate collision around the Tarim basin, which marked a second-order period of the basin evolution. The centers of subsidence showed periodic shifts since the Cambrian, and the time for periodic migration (completing a circle) of the depocenters or the centers of subsidence is traced as 212 ± Ma, which corresponded to the first-order period of the basin evolution. The coupling relationships between the wave processes and the evolution and distribution of source, reservoir and cap rocks in the basin were given by three kinds of patterns, which were important in predicting the space-time distribution of source, reservoir and cap rocks. This study gives a new insight on predicting the formation and distribution of petroleum, which could be used for selecting petroleum exploration targets effectively.

Sequence stratigraphy in the middle Ordovician shale successions, mid-east Korea: Stratigraphic variations and preservation potential of organic matter within a sequence stratigraphic framework

The Jigunsan Formation is the middle Ordovician shale-dominated transgressive succession in the Taebaeksan Basin, located in the eastern margin of the North China platform. The total organic carbon (TOC) content and some geochemical properties of the succession exhibit a stratigraphically distinct distribution pattern. The pattern was closely associated with the redox conditions related to decomposition, bulk sedimentation rate (dilution), and productivity. To explain the distinct distribution pattern, this study attempted to construct a high-resolution sequence stratigraphic framework for the Jigunsan Formation. The shale-dominated Jigunsan Formation comprises a lower layer of dark gray shale, deposited during transgression, and an upper layer of greenish gray siltstone, deposited during highstand and falling stage systems tracts. The concept of a back-stepped carbonate platform is adopted to distinguish early and late transgressive systems tracts (early and late TST) in this study, whereas the highstand systems tracts and falling stage systems tracts can be divided by changes in stacking patterns from aggradation to progradation. The late TST would be initiated on a rapidly back-stepping surface of sediments and, just above the surface, exhibits a high peak in TOC content, followed by a gradually upward decrease. This trend of TOC distribution in the late TST continues to the maximum flooding surface (MFS). The perplexing TOC distribution pattern within the late TST most likely resulted from both a gradual reduction in productivity during the late TST and a gradual increase in dilution effect near the MFS interval. The reduced production of organic matter primarily incurred decreasing TOC content toward the MFS when the productivity was mainly governed by benthic biota because planktonic organisms were not widespread in the Ordovician. Results of this study will help improve the understanding of the source rock distribution in mixed carbonate–siliciclastic successions within a stratigraphic framework, particularly for unconventional shale reservoirs.

Magmatic activities and their impacts on oil/gas formation in the southwestern Ordos Basin, Central China

The southwestern area of the Ordos Basin, China, contains good oil/gas systems, similar to the main basin. However, no oil/gas reserves have been found because some magmatic rocks with different occurrences developed in the region, it resulted in the suspension of oil/gas exploration in the 1980s. By means of integrated research based on field investigation, geophysical interpretation, and data of drilling wells, this paper indicates that magmatic activities in the southwestern Ordos Basin display different properties over multiple periods. The Proterozoic and Palaeozoic magmatic rocks are mainly distributed as a large batholith in the Qinling Orogen, and the Qilian Orogen around the southwestern margin of the Ordos Basin. These Proterozoic and Paleozoic plutons have no effect on hydrocarbon source rocks and oil/gas generation in the Ordos Basin. However, the Mesozoic magmatic activities developed within the basin have obvious effects on oil/gas generation. Three kinds of exploration regions were selected within the southwestern Ordos Basin according to the distribution of hydrocarbon source and magmatic rocks as well as the thermal degree: (a) the marginal area of the basin, (b) the region of the Longmen Uplift distributed with concealed magmatic rocks within the basin, and (c) the region within the basin far away from concealed magmatic rocks. Three sets of gas source rocks, that is, the Upper Proterozoic algal dolostone, the Middle Ordovician dark shale, the Upper Paleozoic black mudstone of coal system, and one set of oil source rocks of the Upper Triassic lacustrine black mudstone and oil shale, are exposed in outcrops near the margin of the basin. They all display a low thermal degree with vitrinite reflectance (Ro) below 1.3%, and they do not contribute to oil/gas accumulation because of earlier tectonic uplift. The gas source rocks and oil source rocks, which occur within the basin area of the Longmen Uplift, where the concealed magmatic rocks, display an abnormal thermal degree of over maturation with Ro over 3.4% and underwent dry gas generation because of heating from magmatic activity, and they have gas exploration potential. The source rocks distributed within the basin area away from concealed magmatic rocks display a normal thermal degree and oil/gas generation. The Ro of the Upper Triassic oil source rock is 1.0–1.6%, which is under the thermal maturity stage of liquid oil generation, whereas that of the Upper Paleozoic gas source rocks is 2.0–2.5% under the thermal maturity stage of gas generation. Measured Ro and burial depth of source rocks in the region show a linear relationship, which indicate that source rocks experienced thermal evolution and oil/gas generation under the normal burial thermal condition rather than the magmatic activity. This region has the most potential for both oil and gas exploration.

3D structural and thermal modelling of Mesozoic petroleum systems in the Po Valley Basin, northern Italy

1D and 3D basin modelling was performed to investigate the Mesozoic carbonate petroleum systems of the Po Valley Basin (northern Italy), through integration of a recent 3D structural model of the study area with the distribution of potential Triassic source rocks, rock properties and heat flow models. Results from standard 1D maturity models show significant overprediction of the thermal maturity of deep Triassic carbonates in the western Po Valley, unless the effect of the substantial overpressure observed in these sequences is incorporated into the model. In order to further test this observation, two thermal scenarios were applied to the Po Valley 3D geo-volume: one based on the actual geological heat flow and a second model based on a reduced heat flow as a proxy for the delaying effect of overpressure on hydrocarbon maturation. The predictions of these two models were then compared with the observed hydrocarbon distribution in the western Po Valley. Both thermal scenarios are broadly consistent with the observed hydrocarbon distribution at the scale of the basin but, in detail, the overpressure model provides a better match between the predicted charge available from the kitchen area's post-critical moment and observed volumes of hydrocarbons initially in place within the traps, as well as with the observed and predicted hydrocarbon phases, as measured by the gas/oil ratio (GOR) of the fluids. Overpressure probably significantly delayed hydrocarbon maturation in the western domain of the basin, confirming results from previous studies. Beyond regional implications, and despite its relative simplicity and inherent uncertainties, the adopted approach demonstrates the potential of a consistent 3D integration of the thermostructural history of sedimentary basins to constrain the geometry and structural evolution of hydrocarbon-bearing traps, as well as the generation and migration of hydrocarbons into these traps.

Mapping deep targets based on integrated 3D MT-gravity interpretation: a case study

Mapping deep geological hydrocarbon targets is of significant importance in basin exploration. In areas lacking reliable seismic data, magnetotelluric (MT) and gravity explorations are helpful to delineate the distribution of potential deep geological hydrocarbon targets. Here we investigate the effectiveness of the integrated 3D MT and gravity explorations for mapping the potential deep hydrocarbon source rocks. The result based on the data from the W Basin (part of the Ordes Basin) of China demonstrates that the method is efficient and economical for basin exploration. The method is particularly useful in target areas which are of great interest for oil and gas exploration but lack high quality seismic data. In our method, we first use the high-precision 3D small-bin MT data acquisition to improve the data accuracy. Then we perform datum static correction method and apply 3D inversion to obtain the3D resistivity distribution. We also develop a layered resistivity model based on resistivity logging to assist the interpretation of the inverted 3D resistivity data so as to derive an initial 3D geological model. Starting from the initial model, we use 2D gravity data to update the model via 2D inversion line by line, and then pass the updated model for the next round of the 3D MT inversion. The integrated inversion is implemented iteratively so the model converges to satisfy the need of final geological analysis. The application to the W Basin shows that we could successfully delineate the geological distribution of the potential deep hydrocarbon source rocks within the basin and map the thickness of the upper Paleozoic.

Hydrocarbon discovery in the Ordovician dolomite reservoirs in the Maigaiti slope, Southwest Depression of the Tarim Basin, and its exploration implications

A high-yield gas flow is produced from the dolomite reservoirs of the Ordovician Penglaiba Fm in Well Luosi 2 in the Southwest Depression of the Tarim Basin, recording as the most important major oil and gas discovery in the Maigaiti slope in recent 20 years. In this paper, the success and failure of wells drilled into the Ordovician during the exploration in the Maigaiti slope and its periphery were analyzed to clarify the future exploration targets in this area. Then, the distribution characteristics of Ordovician limestone weathered crust and internal dolomite reservoirs were investigated, the relationship between structural traps (e.g. formation and evolution) and hydrocarbon accumulation was analyzed, and the main factors controlling the Ordovician hydrocarbon accumulation in this area were defined. Finally, the relationship between hydrocarbon distribution and Neoproterozoic rift system was discussed. Accordingly, some findings were obtained. First, the Ordovician dolomite reservoirs are more developed than limestone reservoirs. Limestone weathered crust reservoirs of Middle Ordovician Yingshan Fm (upper member) are mainly distributed in fault zones, and their reservoir space is mainly composed of high-angle unfilled fractures. Internal dolomite reservoirs of Lower Ordovician Yingshan Fm (lower member) and Penglaiba Fm are laterally and stably distributed and their reservoir space is mainly composed of small dissolved pores which present “strings of beads” reflection characteristics on seismic profiles. Second, the Ordovician hydrocarbon is mainly discovered in the fault zones and the lithologic traps consisting of Ordovician karst dolomite reservoirs at periclines are the main exploration targets in subsequent operations. Third, the distribution of Cambrian source rocks is the key factor restricting the success rate of Ordovician oil and gas exploration. Under the control of Neoproterozoic rift system in the SW Tarim depression, the middle section of this depression is favorable for oil and gas exploration, and it includes multiple hydrocarbon source–reservoir–caprock assemblages, such as Ordovician–Upper Cambrian dolomites and Carboniferous mudstones, and Lower Cambrian dolomite and Middle Cambrian gypsum salt rocks.

Formation and evolution of intraplatform basin from the late Sinian to early Cambrian in Sichuan Basin, China

Based on the drilling, logging, seismic and outcrop data, the formation and evolution of the late Sinian to early Cambrian intraplatform basin in Sichuan Basin was studied. Through the analysis of the total residual thickness of Member 3 + Member 4 of Dengying Formation, the total thickness of Maidiping Formation + Qiongzhusi Formation, and lithofacies characteristics of Maidiping Formation, the distribution of the intraplatform basin was defined and its controlling effect on natural gas distribution of Dengying Formation was revealed. The intraplatform basin was characterized by small total residual thickness of Member 3 and Member 4 of Dengying Formation, the large total thickness of Maidiping Formation and Qiongzhusi Formation, and the deep-water phosphorous-carbonaceous-siliceous mudstone in Maidiping Formation. Horizontally, the intraplatform basin was mainly distributed in Qingchuan-Ziyang-Yibin area, and experienced four evolution periods. During the period of Member 1 and Member 2 of Dengying Formation, the Sichuan Basin was a rimmed carbonate platform with the well developed mounds and shoals on the platform margin and its interior. The intraplatform basin in western Sichuan Basin was initially formed due to the first episode of Tongwan movement. During the period of Member 3 and Member 4 of Dengying Formation, the depositional center was formed in Moxi, Changning and Zhengxiong area due to extension and rifting of the Upper Yangtze Craton, thereafter, the Sichuan Basin evolved into a rimmed carbonate platform with an intraplatform basin. The second episode of Tongwan movement between Sinian and Cambrian led to the overall uplift and exposure of Sichuan Basin characterized by weathering denudation at high position and downward fluid erosion at low position. During the period of Maidiping Formation, three lithofacies zones were developed horizontally, and the third episode of the Tongwan movement between Maidiping Formation and Qiongzhusi Formation modified the sedimentary geomorphology locally. During the period of Qiongzhusi Formation and Canglangpu Formation, continuous deposition made the Sichuan Basin evolve into a gentle siliciclastic ramp. The evolution of the intraplatform basin not only promoted formation of high-quality platform-margin dolomite reservoirs of Member 4 of Dengying Formation, but also controlled distribution of the high-quality source rocks of Maidiping Formation and Qiongzhusi Formation. The dolomite of Dengying Formation in the surrounding area of the intraplatform basin was the most favorable hydrocarbon exploration area because of its good source-reservoir configuration.

Characteristics and controlling factors of lacustrine tight oil reservoirs of the Triassic Yanchang Formation Chang 7 in the Ordos Basin, China

Tight sandstone oil reservoirs have received increasing attention in petroleum exploration and exploitation. Previous research concerning tight oil reservoirs has predominantly focused on marine basins. However, in China, tight oil reservoirs are mostly distributed in lacustrine basins. Taking the tight oil sandstones of the Yanchang Formation Chang 7 oil reservoir interval (the Chang 7 for short) in the Ordos Basin as an example, five factors are identified that control their formation and occurrence. Firstly, three episodes of oil charging took place during the Early Cretaceous, which were 142–139 Ma, 128–122 Ma and 114–106 Ma, respectively. Continuous generation and episodic expulsion led to multiple episodes of oil accumulation. Secondly, widely distributed source rocks (TOC > 1.0%) provide hydrocarbons to the Chang 7. The distribution of tight oil was controlled by the outer boundary of the source rock distribution, while the transition areas between generation (expulsion) centers were the accumulation and enrichment zones in the Chang 7. Thirdly, with the favorable conditions for retained hydrocarbons, massive continuous tight reservoir beds (average porosity = 7.6% and average permeability = 0.15 mD) developed in the Chang 7 capable of forming large-scale successive tight oil reservoirs. Fourthly, different source-reservoir assemblages have different expulsion patterns and amounts, which led to different charging degrees and sizes of tight oil accumulations. Type III (source-reservoir interbeds) will be the most favorable target for exploration and exploitation in the Chang 7, Ordos Basin. Finally, under the driving mechanism of non-buoyancy migration and accumulation, pressure differences between source and reservoir rocks (PDBSR) serve as the primary expulsion and migration force for crude oil during the main accumulation periods in the Chang 7.