Mechanisms of petroleum accumulation in the Bozhong sub-basin, Bohai Bay Basin, China. Part 1: Origin and occurrence of crude oils

The origin of the fourteen major oil fields in the Bozhong sub-basin, Bohai Bay basin was studied based on the results of Rock-Eval pyrolysis on more than 700 samples and biomarker analysis on 61 source rock samples and 87 oil samples. The three possible source rock intervals have different biomarker assemblages and were deposited in different environments. The third member of the Oligocene Dongying Formation (E₃d₃, 32.8–30.3 Ma in age) is characterized mainly by high C₁₉/C₂₃ tricyclic terpane (>0.75), high C₂₄ tetracyclic terpane/C₂₆ tricyclic terpane (>2.5), low gammacerane/αβ C₃₀ hopane (<0.15) and low 4-methyl steranes/ΣC₂₉ steranes (<0.15) ratios, and was deposited in sub-oxic to anoxic environments with significant terrigenous organic matter input. The first (E₂s₁, 35.8–32.8 Ma) and third (E₂s₃, 43.0–38.0 Ma) members of the Eocene Shahejie Formation have low C₁₉/C₂₃ tricyclic terpane and low C₂₄ tetracyclic terpane/C₂₆ tricyclic terpane ratios and were deposited in anoxic environments with minor terrestrial organic matter input, but have different abundances of 4-methyl steranes and gammacerane. The hydrocarbon-generating potential and biomarker associations of these three source rock intervals were controlled by tectonic evolution of the sub-basin and climate changes. Three oil families derived from E₂s₃, E₂s₁ and E₃d, respectively, and three types of mixed oils have been identified. All large oil fields in the Bozhong sub-basin display considerable heterogeneities in biomarker compositions and originated from more than one source rock interval, which suggests that mixing of oils derived from multiple source rock intervals or multiple generative kitchens, and/or focusing of oils originated from a large area of a generative kitchen, is essential for the formation of large oil fields in the Bozhong sub-basin. E₂s₃- and E₂s₁-derived oils experienced relatively long-distance lateral migration and accumulated in traps away from the generative kitchen. E₃d₃-derived oils had migrated short distances and accumulated in traps closer to the generative kitchen. Such a petroleum distribution pattern has important implications for future exploration. There is considerable exploration potential for Dongying-derived oils in the Bozhong sub-basin, and traps close to or within the generative kitchens have better chance to contain oils generated from the Dongying Formation.     

Petroleum generation and charge history of the northern Dongying Depression,Bohai Bay Basin,China: Insight from integrated fluid inclusion analysis and basin modelling

The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R_o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R_o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation.     

Charging of the Penglai 9-1 oil field,Bohai Bay basin,China: Functions of the delta on accumulating petroleum

The Penglai 9-1 (PL9-1) oil field, which contains China's third largest offshore oil accumulation (in-place reserves greater than 2.28 × 10⁸ ton or 1.49 × 10⁹ bbl), was found in shallow reservoirs (700–1700 m, 2297–5577 ft) within the most active fault zone in east China. The PL9-1 field contains two oil-bearing series, the granite intrusions in Mesozoic (Mz) and both the sandstone reservoirs in Neogene Guantao (Ng) and Neogene Minghuazhen (Nm) Formation. The origins of the PL9-1 field, both in terms of source rock intervals and generative kitchens, were determined by analyzing biomarker distributions for 61 source rock samples and 33 oil samples. The Mesozoic granite intrusions, which hold more than 80% of the oil reserves in the field, were charged in the west by oil generated from the third member (Es₃) of the Shahejie Formation in the Bodong depression. The Neogene reservoirs of the PL9-1 field were charged in the west by oil generated from the third member (Es₃) of the Shahejie Formation in the Bodong depression and in the south by oil generated from the first member (Es₁) of the Shahejie Formation in the Miaoxibei depression. Interactive contact between the large fan delta and the mature source rocks residing in the Es₃ Formation of the Bodong depression resulted in a high expulsion efficiency from the source rocks and rapid oil accumulation in the PL9-1 field, which probably explains how can this large oil field accumulate and preserve within the largest and most active fault zone in east China.     

The origin and charging directions of Neogene biodegraded oils: A geochemical study of large oil fields in the middle of the Shijiutuo Uplift,Bohai Sea,China

Two large oil fields (QHD32-6 and QHD33-1), located in the middle part of the Shijiutuo Uplift, have generally suffered mild biodegradation. Based on multivariate statistical analysis of the biomarker parameters, this study discussed the origin and charging directions for these two oil fields.In contrast to Ed₃-derived oil, all available oil samples from these two large oil fields displayed low C₁₉/C₂₃, C₂₄/C₂₆ and high G/H and 4-MSI, which are attributed to the mixtures of oils derived from the Shahejie (Es₁ and Es₃) source rocks. Oils in QHD32-6, which contain relatively more Es₃-derived oil, are called Group I oils, and most oils in QHD33-1, which share relatively more Es₁-derived oil, are called Group II oils. Our mixed oil experiments reveal the predominant Es₃- and Es₁-derived oil contribution for Group I and Group II oil groups, respectively; however, the selection of end member oils warrants further research.Based on comparisons of biomarker parameters, the QHD32-6 oil field was mainly charged in the north by oil generated from Shahejie formation source rocks in the Bozhong depression. However, oils from the north of QHD32-6 field display a remarkable difference to the oils in the south of this field, which may indicate that a charging pathway exists from the QHD33-1 field. Considering the variations in biomarker compositions in the west to -east and northwest to -southeast sections across the QHD33-1 and QHD32-6 oil fields, it can be deduced that Es₃-sourced oil migrated westward to the QHD32-6 traps, and then charging by Es₁ oil from the Bozhong Sag resulted in the QHD33-1 oil field being characterized by the mixture of Es₃- and Es₁-sourced oil. Moreover, migration of Es₁-derived oil from the Qinnan Sag was not identified, implying that the QHD33-1 oil field is mainly charged from the northeast of the Bozhong Sag.     

Organic geochemistry and reservoir characterization of the organic matter-rich calcilutite in the Shulu Sag,Bohai Bay Basin,North China

Although extensive studies have been conducted on unconventional mudstone (shales) reservoirs in recent years, little work has been performed on unconventional tight organic matter-rich, fine-grained carbonate reservoirs. The Shulu Sag is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin and filled with 400–1000 m of Eocene lacustrine organic matter-rich carbonates. The study of the organic matter-rich calcilutite in the Shulu Sag will provide a good opportunity to improve our knowledge of unconventional tight oil in North China. The dominant minerals of calcilutite rocks in the Shulu Sag are carbonates (including calcite and dolomite), with an average of 61.5 wt.%. The carbonate particles are predominantly in the clay to silt size range. Three lithofacies were identified: laminated calcilutite, massive calcilutite, and calcisiltite–calcilutite. The calcilutite rocks (including all the three lithofacies) in the third unit of the Shahejie Formation in the Eocene (Es₃) have total organic carbon (TOC) values ranging from 0.12 to 7.97 wt.%, with an average of 1.66 wt.%. Most of the analyzed samples have good, very good or excellent hydrocarbon potential. The organic matter in the Shulu samples is predominantly of Type I to Type II kerogen, with minor amounts of Type III kerogen. The temperature of maximum yield of pyrolysate (T_max) values range from 424 to 452 °C (with an average of 444 °C) indicating most of samples are thermally mature with respect to oil generation. The calcilutite samples have the free hydrocarbons (S₁) values from 0.03 to 2.32 mg HC/g rock, with an average of 0.5 mg HC/g rock, the hydrocarbons cracked from kerogen (S₂) yield values in the range of 0.08–57.08 mg HC/g rock, with an average of 9.06 mg HC/g rock, and hydrogen index (HI) values in the range of 55–749 mg HC/g TOC, with an average of 464 mg HC/g TOC. The organic-rich calcilutite of the Shulu Sag has very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The pores in the Shulu calcilutite are of various types and sizes and were divided into three types: (1) pores within organic matter, (2) interparticle pores between detrital or authigenic particles, and (3) intraparticle pores within detrital grains or crystals. Fractures in the Shulu calcilutite are parallel to bedding, high angle, and vertical, having a significant effect on hydrocarbon migration and production. The organic matter and dolomite contents are the main factors that control calcilutite reservoir quality in the Shulu Sag.     

Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin,Muglad Basin,Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.     

Tracing of deeply-buried source rock: A case study of the WC9-2 petroleum pool in the Pearl River Mouth Basin, South China Sea

The identification of a deeply-buried petroleum-source rock, owing to the difficulty in sample collection, has become a difficult task for establishing its relationship with discovered petroleum pools and evaluating its exploration potential in a petroleum-bearing basin. This paper proposes an approach to trace a deeply-buried source rock. The essential points include: determination of the petroleum-charging time of a reservoir, reconstruction of the petroleum generation history of its possible source rocks, establishment of the spatial connection between the source rocks and the reservoir over its geological history, identification of its effective source rock and the petroleum system from source to trap, and evaluation of petroleum potential from the deeply-buried source rock. A case study of the W9-2 petroleum pool in the Wenchang A sag of the Pearl River Mouth Basin, South China Sea was conducted using this approach. The W9-2 reservoir produces condensate oil and gas, sourced from deeply-buried source rocks. The reservoir consists of a few sets of sandstone in the Zhuhai Formation, and the possible source rocks include an early Oligocene Enping Formation mudstone and a late Eocene Wenchang Formation mudstone, with a current burial depth from 5000 to 9000 m. The fluid inclusion data from the reservoir rock indicate the oil and the gas charged the reservoir about 18–3.5 Ma and after 4.5 Ma, respectively. The kinetic modeling results show that the main stages of oil generation of the Wenchang mudstone and the Enping mudstone occurred during 28–20 Ma and 20–12 Ma, respectively, and that the δ¹³C₁ value of the gas generated from the Enping mudstone has a better match with that of the reservoir gas than the gas from the Wenchang mudstone. Results from a 2D basin modeling further indicate that the petroleum from the Enping mudstone migrated upward along the well-developed syn-sedimentary faults in the central area of the sag into the reservoir, but that the petroleum from the Wenchang mudstone migrated laterally first toward the marginal faults of the sag and then migrated upward along the faults into shallow strata. The present results suggest that the trap structure in the central area of the sag is a favorable place for the accumulation of the Enping mudstone-derived petroleum, and that the Wenchang mudstone-derived petroleum would have a contribution to the structures along the deep faults as well as in the uplifted area around the sag.     

Early Cenozoic paleontological assemblages and provenance evolution of the Lishui Sag,East China Sea

The East China Sea Shelf Basin generated a series of back-arc basins with thick successions of marine- and terrestrial-facies sediments during Cenozoic. It is enriched with abundant oil and gas resources and is of great significance to the petroleum exploration undertakings. Therein, the Lishui Sag formed fan delta, fluvial delta and littoral-to-neritic facies sediments during Paleocene–Eocene, and the research on its sedimentary environment and sediment source was controversial. This study analyzed the paleontological combination characteristics, and conducted a source-to-sink comparative analysis to restore the sedimentary environment and provenance evolution of the Lishui Sag during Paleocene–Eocene based on the integration of detrital zircon U-Pb age spectra patterns with paleontological assemblages. The results indicated that Lishui Sag was dominated by littoral and neritic-facies environment during time corroborated by large abundance of foraminifera, calcareous nannofossils and dinoflagellates. Chronological analysis of detrital zircon U-Pb revealed that there were significant differences in sediment sources between the east and west area of the Lishui Sag. The western area was featured by deeper water depths in the Paleocene–Eocene, and the sediment was characterized by a single Yanshanian peak of zircon U-Pb age spectra, and mainly influenced from Yanshanian magmatic rocks of South China Coast and the surrounding paleo-uplifts. However, its eastern area partly showed Indosinian populations. In particular, the upper Eocene Wenzhou sediments were featured by increasingly plentiful Precambrian zircons in addition to the large Indosinian-Yanshanian peaks, indicating a possible impact from the Yushan Low Uplift to the east. Therefore, it is likely that the eastern Lishui Sag generated large river systems as well as deltas during time. Due to the Yuquan Movement, the Lishui Sag experienced uplifting and exhumation in the late stage of the late Eocene and was not deposited with sediments until Miocene. Featured by transitional-facies depositions of Paleocene–Eocene, the Lishui Sag thus beared significant potential for source rock and oil-gas reservoir accumulation.     

东海盆地X凹陷Y气田的天然气成因、成藏模式及勘探意义

本文旨在厘清东海盆地X凹陷Y气田天然气成因,建立成藏模式,以指导下步勘探部署。本文从天然气组分、烷烃气碳同位素、轻烃、凝析油生物标志化合物等分析入手,系统研究了油气成因类型及来源,并结合构造演化史、生烃史分析,建立了Y气田成藏模式,提出了大中型气田的勘探方向。主要认识如下:（1）天然气组分碳同位素、轻烃和埋藏史分析表明,Y气田天然气为凹中始新统平湖组烃源岩在龙井运动期（距今13 Ma）生成的高成熟煤型气;（2）凝析油姥鲛烷/植烷、规则甾烷等特征,反映了凹中区平湖组烃源岩发育于弱氧化?弱还原潮坪、潟湖沉积环境,生烃母质中存在一定数量的低等水生生物;（3）Y气田具有“凹中区平湖组烃源岩、花港组大型水道砂储集体、挤压构造作用”时空耦合的成藏模式,明确了凹中挤压背斜带是X凹陷大中型气田勘探的主攻方向。     

Basin modeling of the Late Miocene Zeit source rock in the Sudanese portion of Red Sea Basin: Implication for hydrocarbon generation and expulsion history

The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m². The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source.The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m², increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene.The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin.     

南黄海盆地北部坳陷北凹油气成藏特征的再认识

南黄海盆地北部坳陷北凹是一个大中型的中、新生代沉积凹陷,经过四十余年的油气勘探,至今仍无商业油气发现,仅发现诸城1-2一个含油气构造.北凹的油气勘探存在诸多问题,其中是否发育优质烃源岩、烃源岩能否生烃、油气是否运移至储层是关系到北凹油气勘探的基础地质问题.在对北凹主要烃源岩分析评价的基础上,采用流体包裹体系统分析技术,对北凹油气成藏特征展开研究.研究认为,北凹存在白垩系泰二段主力烃源岩,为中深湖相,生烃指标较好,分布面积较大,且现今已经成熟并排烃,生烃中心位于ZC-A井区.油气通过断裂发生垂向运移,已充注至始新统戴南组储层.流体包裹体荧光观察结果及显微测温结果均表明戴南组至少存在两期油充注,第一期发生在35 Ma左右,第二期为现今.     

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin,eastern Yemen

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S₁ + S₂) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.     

Hydrocarbon charging and accumulation history in the Niudong Buried Hill Field in the Baxian Depression,eastern China

The Niudong Buried Hill Field, which lies in the Baxian Depression of the Bohai Bay Basin, is the deepest oil/gas accumulation in eastern China. Its Precambrian dolomite reservoir occurs at burial depths of 5860 m–6027 m. This paper attempts to document the hydrocarbon charging and accumulation history in this field, which could greatly enhance the understanding of the mechanisms for the formation of deep hydrocarbon accumulations. Our previous study of oil trapped in fluid inclusions has demonstrated that the ratio parameters of the fluorescence spectral intensities at 425 nm and 433 nm (Q_425/433 ratio), and at 419 nm and 429 nm (Q_419/429 ratio) can be more effective for revealing hydrocarbon charging history than the previously-used fluorescence parameters such as Lambda max and red/green quotient as well as fluorescence colors. The hydrocarbon charging and accumulation history in the Niudong Buried Hill Field was studied with an integrated approach involving the application of these two spectral parameters of petroleum inclusion fluorescence as well as utilization of other data including homogenization temperatures of aqueous inclusions coeval with petroleum inclusions, and cross-cutting relationships of cements and “oil veins” in pores and fractures. The results indicate that the dolomite reservoir in the Niudong Buried Hill Field experienced three episodes of hydrocarbon charging. In the first two episodes (between 38.5Ma and 25Ma), the low mature and mature oils, which were derived from source rocks in the Sha-4 Member of the Eocene Shahejie Formation, migrated into the reservoir, but part of them leaked out due to normal faulting at the updip margin of the buried hill. These early-charged oils were preserved mainly in small pores in micritic dolomites by oil-wettability and capillary pressure. In the Neogene, the basin subsided as a whole and local faults at the updip margin became inactive and played a sealing role. By approximately 13Ma, the source rocks became highly mature and the generated hydrocarbons then migrated into the reservoir and accumulated. Therefore, the last charging is the most important for hydrocarbon accumulation in the Niudong Buried Hill Field.     

Hydrocarbon generation and expulsion characteristics of Eocene source rocks in the Huilu area,northern Pearl River Mouth basin,South China Sea: Implications for tight oil potential

In recent years, new oil reservoirs have been discovered in the Eocene tight sandstone of the Huilu area, northern part of the Pearl River Mouth basin, South China Sea, indicating good prospects for tight oil exploration in the area. Exploration has shown that the Huilu area contains two main sets of source rocks: the Eocene Wenchang (E₂w) and Enping (E₂e) formations. To satisfy the requirements for further exploration in the Huilu area, particularly for tight oil in Eocene sand reservoirs, it is necessary to re-examine and analyze the hydrocarbon generation and expulsion characteristics. Based on mass balance, this study investigated the hydrocarbon generation and expulsion characteristics as well as the tight oil resource potential using geological and geochemical data and a modified conceptual model for generation and expulsion. The results show that the threshold and peak expulsion of the E₂w source rocks are at 0.6% vitrinite reflectance and 0.9% vitrinite reflectance, respectively. There were five hydrocarbon expulsion centers, located in the western, eastern, and northern Huizhou Sag and the southern and northern Lufeng Sag. The hydrocarbon yields attributed to E₂w source rocks are 2.4 × 10¹¹ tons and 1.6 × 10¹¹ tons, respectively, with an expulsion efficiency of 65%. The E₂e source rock threshold and peak expulsion are at 0.65% vitrinite reflectance and 0.93% vitrinite reflectance, respectively, with hydrocarbon expulsion centers located in the centers of the Huizhou and Lufeng sags. The yields attributed to E₂e source rocks are 1.1 × 10¹¹ tons and 0.2 × 10¹¹ tons, respectively, with an expulsion efficiency of 20%. Using an accumulation coefficient of 7%–13%, the Eocene tight reservoirs could contain approximately 1.3 × 10¹⁰ tons to 2.3 × 10¹⁰ tons, with an average of 1.8 × 10¹⁰ tons, of in-place tight oil resources (highest recoverable coefficient can reach 17–18%), indicating that there is significant tight oil potential in the Eocene strata of the Huilu area.     

东营凹陷王家岗地区王古1潜山构造特征及油气成藏条件

进一步了解王古1潜山的构造特征及成藏条件,利用渤海湾盆地济阳坳陷东营凹陷王家岗地区的大量三维地震剖面和一些钻井资料,并结合东营凹陷南坡缓坡带区域构造背景及成藏条件分析认为,王古1潜山初始发育于印支期,后经燕山期拉张断陷,切割为断块并抬升,最后于燕山期定型,为典型的缓坡盆倾残丘潜山。该潜山被NW向和NE向断裂切割,潜山高部位侵蚀风化严重,上覆孔店组盖层及沙河街组烃源岩,油气通过断层和不整合面运移至潜山顶部形成侵蚀残丘型油气藏。     

Geochemistry and zircon U-Pb ages of the Oligocene sediments in the Baiyun Sag,Zhujiang River Mouth Basin

In this study, element geochemistry and zircon chronology are used to analyze the Oligocene sediments in the Baiyun Sag, Zhujiang River Mouth Basin. The experimental results are discussed with respect to weathering conditions, parent rock lithologies, and provenances. The chemical index of alteration and the chemical index of weathering values of mudstone samples from the lower Oligocene Enping Formation indicate that clastic particles in the study area underwent moderate weathering. Mudstone samples exhibit relatively enriched light rare earth elements and depleted heavy rare earth elements, "V"-shaped negative Eu anomalies, and negligible Ce anomalies. The rare earth element distribution curves are obviously right-inclined, with shapes and contents similar to those of post-Archean Australian shale and upper continental crust, indicating that the samples originated from acid rocks in the upper crust. The Hf-La/Th and La/Sc-Co/Th diagrams show this same origin for the sediments in the study area. For the samples from the upper Enping deltas, the overall age spectrum shows four major age peaks ca. 59–68 Ma, 98–136 Ma, 153–168 Ma and 239–260 Ma. For the Zhuhai Formation samples,the overall age spectrum shows three major age peaks ca. 149 Ma, 252 Ma and 380 Ma. The detrital zircon shapes and U-Pb ages reveal that during Oligocene sedimentation, the sediments on the northwestern margin of the Baiyun Sag were supplied jointly from two provenances: Precambrian-Paleozoic metamorphic rocks in the extrabasinal South China fold zone and Mesozoic volcanic rocks in the intrabasinal Panyu Low Uplift, and the former supply became stronger through time. Thus, the provenance of the Oligocene deltas experienced a transition from an early proximal intrabasinal source to a late distal extrabasinal source.     

Organic geochemistry of the Silurian Tanezzuft Formation and crude oils,NC115 Concession,Murzuq Basin,southwest Libya

Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.     

Temporal changes of fault seal and early charge of the Maui Gas-condensate field,Taranaki Basin,New Zealand

Fault seal due to juxtaposition or the generation of low-permeability fault rock has the potential to change through time with displacement accumulation. Temporal variations in cross-fault flow of hydrocarbons have been assessed for the Cape Egmont Fault (CEF), Taranaki Basin New Zealand, using displacement backstripping, juxtaposition and Shale Gouge Ratio (SGR) analysis. The timing of hydrocarbon migration and charge of the giant Maui Gas-condensate Field across the CEF have been assessed using seismic reflection lines (2D & 3D), coherency cubes, VShale curves from the Maui-2 well and PetroMod modelling. Displacement–backstripping analysis suggests that between the Late Miocene and early Pleistocene (5.5 and 2.1 Ma) sandstone reservoir units of the Maui Field (Mangahewa, Kaimiro and Farewell Formations) and underlying source rocks (Rakopi Formation) were partly juxtaposed across the CEF with low SGRs (< 0.2) present in the fault zone. Following 2.1 Ma SGRs increased to 0.2–0.55 adjacent to the Eocene–Palaeocene reservoir succession which was not in juxtaposed contact with source rocks. PetroMod modelling using these SGR values and juxtaposition relationships supports cross-fault flow prior to 2.1 Ma with later charge across the fault being less likely. Gas chimneys and the gas–water contact in the Eocene reservoir proximal to the fault suggest that despite limited cross-fault flow, upward leakage of hydrocarbons from the reservoir occurred after 2.1 Ma, possibly associated with active fault movement or fracturing related to faulting, and may account for the loss of an early oil phase.     

Thermal evolution of the Kuh-e-Asmari and Sim anticlines in the Zagros fold-and-thrust belt: Implications for hydrocarbon generation

Mixed layer clay minerals, vitrinite reflectance and geochemical data from Rock-Eval pyrolysis were used to constrain the burial evolution of the Mesozoic–Cenozoic successions exposed at the Kuh-e-Asmari (Dezful Embayment) and Sim anticlines (Fars province) in the Zagros fold-and-thrust belt. In both areas, Late Cretaceous to Pliocene rocks, show low levels of thermal maturity in the immature stages of hydrocarbon generation and early diagenetic conditions (R0 I–S and R_o% values < 0.5). At depths of 2–4 km, T_max values (435–450 °C) from organic-rich layers of the Sargelu, Garau and Kazhdumi source rocks in the Kuh-e-Asmari anticline indicate mid to late mature stages of hydrocarbon generation. One dimensional thermal models allowed us to define the onset of oil generation for the Middle Jurassic to Eocene source rocks and pointed out that sedimentary burial is the main factor responsible for measured levels of thermal maturity. Specifically, the Sargelu and Garau Formations entered the oil window prior to Zagros folding in Late Cretaceous times, the Kazhdumi Formation during middle Miocene (syn-folding stage), and the Pabdeh Formation in the Late Miocene–Pliocene after the Zagros folding. In the end, the present-day distribution of oil fields in the Dezful Embayment and gas fields in the Fars region is primarily controlled by lithofacies changes and organic matter preservation at the time of source rock sedimentation. Burial conditions during Zagros folding had minor to negligible influence.     

Palynology and petroleum potential of the Kazhdumi Formation (Cretaceous: Albian–Cenomanian) in the South Pars field,northern Persian Gulf

The Kazhdumi Formation of the Bangestan Group is a well-known source rock that has produced abundant oil in most petroleum fields in the Zagros Basin, which stretches from northwest to southwest Iran over hundreds of kilometres. The formation reaches a thickness of 230 m at the type section in northwest Zagros but thins out to 40–50 m in wells studied from the South Pars giant petroleum field, where it comprises mainly grey shales with occasional intercalations of marls and sandstones. South Pars, best known as the Iranian part of the world's largest non-associated gas field, contains small quantities of oil above and below the Kazhdumi Formation.