库车前陆逆冲带天然气成藏期与成藏史

根据圈闭形成时间、油气成熟度、有机包裹体特征等综合分析认为,库车前陆逆冲带具有多期油气运移注入的历史,主要运移充注事件有晚第三纪康村早中期(17～10Ma)、康村晚期—库车早中期(10～3Ma)、库车晚期—第四纪西域期(3～1Ma)3期.其中库车晚期—西域期是库车前陆逆冲带天然气藏形成的主要时期,康村期—库车早中期则主要是原生油藏和凝析气藏的形成时期,但此阶段形成的油藏和凝析气藏在库车晚期—西域期因受到大量高过成熟气的气侵作用以及构造破坏作用而多形成次生油藏甚至破坏散失.     

CHARGING OF ORDOVICIAN RESERVOIRS IN THE HALAHATANG DEPRESSION (TARIM BASIN,NW CHINA) DETERMINED BY OIL GEOCHEMISTRY

Petroleum at Halahatang oilfield in the Halahatang Depression (Tabei Uplift, Tarim Basin, NW China) occurs within calcarenites and bioclastic limestones in the Middle Ordovician Yijianfang Formation (O_2yj). The petroleum is sourced from intervals in the Upper Ordovician Lianglitage Formation (O_3l), and reservoirs are sealed by Upper Ordovician – Silurian argillaceous limestones and marls. The charging history of Halahatang oilfield is however poorly understood. For this study, the geochemical characteristics of 17 oils from Ordovician reservoir rocks at Halahatang field were investigated by GC and GC‐MS. Oil‐oil correlation studies indicate that all the oils belong to a single mature oil population. Based on the co‐occurrence of an intact n‐alkanes series together with an unresolved complex mixture (UCM) and fully‐developed 25‐norhopanes in the same oil samples, as well as a bimodal distribution of homogenisation temperatures of aqueous fluid inclusions, it was concluded that the reservoir experienced two separate oil charge events. 1D basin modelling indicates that the early phase of charging occurred from about 412 to 409 Ma and the later phase from 11 to 9 Ma. Using molecular parameters as tracing indicators, the general direction of oil charging was deduced to be from south to north. The source kitchen is therefore inferred to be located to the south of the Halahatang oilfield, probably in the Shuntuoguole Uplift between the Awati and Manjiaer Depressions.     

塔里木盆地满东地区油气成藏特征分析

塔里木盆地满东地区的成藏物质基础、成藏事件和成藏模式分析表明,该地区除发育寒武系—中下奥陶统高有机质丰度的干酪根型烃源岩外,还发育以古油藏形式为主的"再生烃源",油气藏的形成可分为3个发展阶段:1)中加里东期的古隆起发育、古油气藏形成阶段;2)晚加里东期—印支期的古隆起隆升剥蚀、古油藏破坏并调整阶段;3)晚燕山期—喜山期的上构造层褶皱断裂发育、圈闭形成、以古油藏裂解气充注为主的阶段。晚燕山期—喜山期可能是该区最具有效规模的成藏期,并以形成气藏为主。     

BURIAL,TEMPERATURE AND MATURATION HISTORY OF CRETACEOUS SOURCE ROCKS IN THE NW PERSIAN GULF,OFFSHORE SW IRAN: 3D BASIN MODELLING

This study presents a 3D numerical model of a study area in the NW part of the Persian Gulf, offshore SW Iran. The purpose is to investigate the burial and thermal history of the region from the Cretaceous to the present day, and to investigate the location of hydrocarbon generating kitchens and the relative timing of hydrocarbon generation/migration versus trap formation. The study area covers about 20,000 km² and incorporates part of the intra‐shelf Garau‐Gotnia Basin and the adjacent Surmeh‐Hith carbonate platform. A conceptual model was developed based on the interpretation of 2700 km of 2D seismic lines, and depth and thickness maps were created tied to data from 20 wells. The thermal model was calibrated using bottom‐hole temperature and vitrinite reflectance data from ten wells, taking into account the main phases of erosion/non‐deposition and the variable temporal and spatial heat flow histories. Estimates of eroded thicknesses and the determination of heat‐flow values were performed by burial and thermal history reconstruction at various well and pseudo‐well locations. Burial, temperature and maturation histories are presented for four of these locations. Detailed modelling results for Neocomian and Albian source rock successions are provided for six locations in the intra‐shelf basin and the adjacent carbonate platform. Changes in sediment supply and depocentre migration through time were analyzed based on isopach maps representing four stratigraphic intervals between the Tithonian and the Recent. Backstripping at various locations indicates variable tectonic subsidence and emergence at different time periods. The modelling results suggest that the convergence between the Eurasian and Arabian Plates which resulted in the Zagros orogeny has significantly influenced the burial and thermal evolution of the region. Burial depths are greatest in the study area in the Binak Trough and Northern Depression. These depocentres host the main kitchen areas for hydrocarbon generation, and the organic‐rich Neocomian and Albian source rock successions have been buried sufficiently deeply to be thermally mature. Early oil window maturities for these successions were reached between the Late Cretaceous (90 Ma) and the early Miocene (18 Ma) at different locations, and hydrocarbon generation may continue at the present‐day.     

ORGANIC GEOCHEMISTRY,BURIAL HISTORY AND HYDROCARBON GENERATION MODELLING OF THE UPPER JURASSIC MADBI FORMATION,MASILA BASIN,YEMEN

The Masila Basin is an important hydrocarbon province in Yemen but the origin of its hydrocarbons is not fully understood. In this study, we evaluate Upper Jurassic source rocks in the Madbi Formation and assess the results of basin modelling in order to improve our understanding of burial history and hydrocarbon generation. This source rock has generated commercial volumes of hydrocarbons which migrated into Jurassic and Lower Cretaceous reservoir rocks. Cuttings samples of shales from the Upper Jurassic Madbi Formation from boreholes in the centre-west of the Masila Basin were analysed using organic geochemistry (Rock-Eval pyrolysis, extract analysis) and organic petrology. The shales generally contain more than 2.0 wt % TOC and have very good to excellent hydrocarbon potential. Kerogen is predominantly algal Type II with minor Type I. Thermal maturity of the organic matter is R_r 0.69–0.91%. Thermal and burial history models indicate that the Madbi Formation source rock entered the early-mature to mature stage in the Late Cretaceous to Early Tertiary. Hydrocarbon generation began in the Late Cretaceous, reaching maximum rates during the Early Tertiary. Cretaceous subsidence had only a minor influence on source rock maturation and OM transformation.     

HYDROCARBON POTENTIAL AND PALAEO‐DEPOSITIONAL ENVIRONMENT OF LACUSTRINE SOURCE ROCKS: MIDDLE JURASSIC SHIMENGOU FORMATION,NORTHERN QAIDAM BASIN,NW CHINA

The Middle Jurassic Shimengou Formation in the Qaidam Basin, NW China, includes coals and lacustrine source rocks which locally reach oil shale quality (i.e. yielding >3.5 % oil on low‐temperature distillation). In the present study, the palaeo‐depositional environment and hydrocarbon potential of the 84.5 m thick Shale Member of the Shimengou Formation are investigated based on bulk geochemical parameters, organic petrographic data, biomarker analysis, and stable isotope geochemistry of 88 core samples. The Shale Member was deposited in an anoxic freshwater lake which formed following the drowning of a precursor low‐lying mire. Variations in bulk geochemical parameters allow four informal units to be identified, referred to (from the base up) as Units 1 to 4. These contain intervals of oil shale of varying thicknesses. In Unit 1, mudstones in the interval referred to as oil shale Layer 1 (true thickness [TD]: 2.06 m) are OM‐rich as a result of algal blooms and photic zone anoxia, and correspond to an initial flooding event. Subsequently, productivity of aquatic organisms decreased, resulting in the deposition of organic‐lean mudstones in Unit 2. Oil shale Layers 2 (TD: 2.03 m) and 3 (TD: 8.03 m) near the base of Unit 3 were deposited during maximum water depths. As with Layer 1, high productivity by algal blooms resulted in photic zone anoxia in a stratified water column. The shales in the upper part of Unit 3 are characterized by high TOC contents and a gradual increased input of terrigenous OM, and were deposited in a stable semi‐deep lake. Finally, organic‐lean mudstones in Unit 4 were deposited in shallow lacustrine conditions. The reconstruction of depositional environments in thick, non‐marine shale‐rich successions by mineralogical, petrographic and inorganic geochemical methods may be challenging as a result of the homogenous composition of component mudstones. The results of this study indicate, however, that sub‐division and basin‐wide correlation of such intervals can be achieved by organic geochemical analyses. Oil shales and organic‐rich mudstones in Units 1 and 3 of the Shimengou Formation Shale Member are excellent oil‐prone source‐rocks with a Source Potential Index of 3.2 t HC/m². Considering the large area covered by the Shimengou Formation in the northern Qaidam Basin (～34,000 km²), the results of this study highlight the regional significance for future petroleum exploration. They indicate that variations in organic productivity and dilution by minerals are key factors controlling the abundance and type of organic matter in the formation. An understanding of these factors will assist with the identification of exploration targets.     

COMPOSITION OF DIAMONDOIDS IN OIL SAMPLES FROM THE ALPINE FORELAND BASIN,AUSTRIA: POTENTIAL AS INDICES OF SOURCE ROCK FACIES,MATURITY AND BIODEGRADATION

Twenty‐seven oil samples from Cretaceous, Eocene and Rupelian reservoir rocks in the Alpine Foreland Basin (Austria) were analysed to evaluate the composition of diamondoid hydrocarbons using gas chromatography – triple quadrupole mass spectrometry. The oils were generated from marly and shaly Oligocene source rocks buried beneath the nappes of the Alpine foldbelt to the south of the study area. Diamondoid hydrocarbons were detected in the saturated fraction of all the analysed oils. A biodegraded oil sample from a shallow reservoir in the NE part of the study area showed an enrichment in diamondoids due to the molecule's high resistance to microbial degradation. Variations in the organic matter type of the source rock facies and differences in maturity are known to influence the composition of diamondoids. However in this study, biomarker‐derived maturity parameters do not show a convincing correlation with diamondoid maturity parameters. Moreover, no cracking trend based on biomarkers and diamondoid concentrations was observed. The results indicate that the composition of diamondoids in oils from the Austrian part of the Alpine Foreland Basin is mainly controlled by heterogeneities in the Lower Oligocene source rocks, including the occurrence of a redeposited source rock succession in the western part of the study area. By contrast, EAI‐1 (the ethyladamantane index) shows a good correlation with various maturity parameters and seems to be independent of source rock facies.     

KINETICS OF HYDROCARBON GAS GENERATION FROM MARINE KEROGEN AND OIL: IMPLICATIONS FOR THE ORIGIN OF NATURAL GASES IN THE HETIANHE GASFIELD, TARIM BASIN, NW CHINA

In this paper we derive kinetic parameters for the generation of gaseous hydrocarbons (C_1‐5) and methane (C₁) from closed‐system laboratory pyrolysis of selected samples of marine kerogen and oil from the SW Tarim Basin. The activation energy distributions for the generation of both C_1‐5 (Ea = 59‐72kcal, A = 1.0×10¹⁴ s^?1) and C₁ (Ea = 61‐78kcal, A = 6.06×10¹⁴ s^?1) hydrocarbons from the marine oil are narrower than those for the generation of these hydrocarbons from marine kerogen (Ea = 50‐74kcal, A = 1.0×10¹⁴ s^?1 for C_1‐5; and Ea = 48‐72kcal, A=3.9×10¹³ s^?1 for C₁, respectively). Using these kinetic parameters, both the yields and timings of C_1‐5 and C₁ hydrocarbons generated from Cambrian source rocks and from in‐reservoir cracking of oil in Ordovician strata were predicted for selected wells along a north‐south profile in the SW of the basin. Thermodynamic conditions for the cracking of oil and kerogen were modelled within the context of the geological framework. It is suggested that marine kerogen began to crack at temperatures of around 120°C (or 0.8 %Ro) and entered the gas window at 138°C (or 1.05 %Ro); whereas the marine oil began to crack at about 140 °C (or 1.1 %Ro) and entered the gas window at 158 °C (or 1.6%Ro). The main geological controls identified for gas accumulations in the Bachu Arch (Southwest Depression, SW Tarim Basin) include the remaining gas potential following Caledonian uplift; oil trapping and preservation in basal Ordovician strata; the extent of breaching of Ordovician reservoirs; and whether reservoir burial depths are sufficiently deep for oil cracking to have occurred. In the Maigaiti Slope and Southwest Depression, the timing of gas generation was later than that in the Bachu Arch, with much higher yields and generation rates, and hence better prospects for gas exploration. It appears from the gas generation kinetics that the primary source for the gases in the Hetianhe gasfield was the Southwest Depression.     

GEOCHEMICAL COMPOSITION OF ORDOVICIAN OILS FROM THE TUOPUTAI REGION,NORTHERN TARIM BASIN,NW CHINA: SOURCE ROCK CORRELATION

Molecular and stable carbon isotope compositions of 46 Ordovician crude oil samples from wells in the Tuoputai region of the northern Tarim Basin were investigated using GC–MS, MRM GC–MS and IRMS to determine their genetic relationships and to identify possible source rocks. Thirty-three source rock samples from outcrops and cores were also investigated. The oil samples varied from light to heavy crudes and showed very narrow δ¹³C value ranges for the whole oil, saturated and aromatic fractions. The majority of the oils displayed very similar molecular compositions with relatively high concentrations of n-alkanes and isoprenoids and low concentrations of terpenoids and steroids. Comparison of the compositions of these crude oils strongly suggested their genetic affinity, while maturity parameters indicated maturity variations from the peak to the late oil generation stages. The samples also showed the characteristics of mixtures of biodegraded and fresh oil charges. Bitumen extracts from Cambrian and Ordovician source rocks were studied in detail. The oil compositions suggested a marine marl source deposited in anoxic, hypersaline conditions with significant bacterial and algal organic matter inputs. The distributions of C₂₆–C₂₈ triaromatic steroids, tricyclic terpanes and regular steranes appear to have been greatly influenced by thermal maturation, making them unreliable for correlating the oils and the source rocks. In contrast, dinosteranes and triaromatic dinosteroids seem not to have been affected by maturation and were more useful for correlation studies. They indicated that there was no or little genetic relationship between the Cambrian – Lower Ordovician source rocks and the oils, but in general suggested a possible Middle – Upper Ordovician source for the oil accumulations in the Tuoputai field. However, the occurrence of triaromatic dinosteroids in oil from well TP28XCX may also suggest a minor contribution from Cambrian – Lower Ordovician source rocks.     

OIL CHARGE HISTORY OF BITUMENS OF DIFFERING MATURITIES IN EXHUMED PALAEOZOIC RESERVOIR ROCKS AT TIANJINGSHAN,NW SICHUAN BASIN,SOUTHERN CHINA

Low‐maturity soft bitumen (or biodegraded heavy oil) and higher maturity solid bitumen are present in Palaeozoic siliciclastics at Tianjingshan in the NW Sichuan Basin, southern China. The origin of these bitumens of variable maturities was investigated. Samples of low‐maturity bitumen from Lower Devonian sandstones and high‐ and low‐maturity bitumen from Upper Cambrian siltstones were analysed to investigate their organic geochemistry and stable isotope compositions. Lower Cambrian and Upper Permian black shales were also investigated to assess their source rock potential, and the burial and maturation history of potential source rocks was modelled using PetroMod. Liquid and gaseous hydrocarbon fluid inclusions in the Devonian sandstones were analysed. Results suggest that both the soft and solid bitumens are derived from crude oil generated by Lower Cambrian organic‐rich black shales. Reservoir rocks at Tianjingshan have experienced two separate oil charge events – in the early‐middle Triassic and early‐middle Jurassic, respectively. The first oil charge was generated by Lower Cambrian black shales in a kitchen area located in the hanging wall of the Tianjingshan fault. The later oil charge was also derived from Lower Cambrian black shales, but the kitchen area was located in the footwall of the fault. Movement on the Tianjingshan fault resulted in progressive burial of the Lower Devonian sandstone reservoir rocks until the end of the middle Triassic, and the “early” charged oil was thermally degraded into high‐maturity solid bitumen. The later‐charged oil was altered into soft bitumen of lower maturiy by biodegradation during uplift of the reservoir after the Jurassic.     

GENERATION AND ACCUMULATION OF HYDROCARBONS IN A DEEP “BURIED HILL” STRUCTURE IN THE BAXIAN DEPRESSION,BOHAI BAY BASIN,EASTERN CHINA

Significant volumes of hydrocarbons have been produced from karstified Infracambrian dolomites in a “buried hill” structure at depths of 5860m to 6027m and reservoir temperatures of 190–201°C in well Niudong‐1 in the Baxian depression, Bohai Bay Basin. This is the deepest oil and gas discovery made in eastern China so far and structures at similar depths are targets for exploration elsewhere in the Bohai Bay Basin. However the origin and accumulation of the hydrocarbons at Niudong‐1 is not clear: they may have been generated from highly mature lacustrine source rocks in the Sha‐4 Member of the Eocene Shahejie Formation; or they may have been derived from thermal cracking of previously‐accumulated oil. This paper investigates the organic geochemistry of the Sha‐4 Member source rocks and the crude oils produced from well Niudong‐1. Analyses of molecular parameters show that the hydrocarbons originated from the pyrolysis of organic matter in Sha‐4 Member source rocks, rather than from cracking of previously accumulated oil. Infracambrian dolomites at the Niudong‐1 location may have been charged with low‐maturity oil around 34 Ma ago, when the Sha‐4 Member source rocks were buried to depths of about 3500m and first entered the oil window. During further rapid burial to more than 5500m starting at about 15Ma, these source rocks became highly mature and generated significant volumes of light oil and gas. Overpressures in the source rock interval forced these hydrocarbons to migrate into unconformably‐underlying Infracambrian dolomite reservoir rocks at the Niudong‐1 structure. Significant risks are associated with future exploration of deep “buried hill” structures in the Bohai Bay Basin. Not all the structures were charged with oil, and accumulations were not necessarily preserved during Neogene burial as the reservoirs may have been breached by faulting.     

BIOMARKER GEOCHEMISTRY OF PALEOGENE CRUDE OILS AND SOURCE ROCKS FROM THE RAOYANG SAG,BOHAI BAY BASIN,NE CHINA: AN OIL – SOURCE ROCK CORRELATION STUDY

This study presents a systematic geochemical analysis of Paleogene crude oils and source rocks from the Raoyang Sag in the Jizhong sub-basin of the Bohai Bay Basin (NE China). The geochemical characteristics of fifty-three oil samples from wells in four sub-sags were analysed using gas chromatography (GC) and gas chromatography – mass spectrometry (GC-MS). Twenty core samples of mudstones from Members 1 and 3 of the Eocene-Oligocene Shahejie Formation were investigated for total organic carbon (TOC) content and by Rock-Eval pyrolysis and GC-MS to study their geochemistry and hydrocarbon generation potential. The oils were tentatively correlated to the source rocks. The results show that three groups of crude oils can be identified. Group I oils are characterized by high values of the gammacerane index and low values of the ratios of Pr/Ph, Ts/Tm, 20S/(20S+20R) C₂₉ steranes, ββ/(ββ+αα) C₂₉ steranes, C₂₇ diasteranes/ C₂₇ regular steranes and C₂₇/C₂₉ steranes. These oils have the lowest maturity and are interpreted to have originated from a source rock containing mixed organic matter deposited in an anoxic saline lacustrine environment. The biomarker parameter values of Group III oils are the opposite to those in Group I, and are interpreted to indicate a highly mature, terrigenous organic matter input into source rocks which were deposited in suboxic to anoxic freshwater lacustrine conditions. The parameter values of Group II oils are between those of the oils in Groups I and III, and are interpreted to indicate that the oils were generated from mixed organic matter in source rocks deposited in an anoxic brackish–saline or saline lacustrine environment. The results of the source rock analyses show that samples from Member 1 of the Shahejie Formation were deposited in an anoxic, brackish – saline or saline lacustrine environment with mixed organic matter input and are of low maturity. Source rocks in Member 3 of the Shahejie Formation were deposited in a suboxic to anoxic, brackish – saline or freshwater lacustrine environment with a terrigenous organic matter input and are of higher maturity. Correlation between rock samples and crude oils indicates that Group I oils were probably derived from Member 1 source rocks, while Group III oils were more likely generated by Member 3 source rocks. The Group II oils with transitional characteristics are likely to have a mixed source from both sets of source rocks.     

CONDENSATES IN THE PY30‐I STRUCTURE,PANYU UPLIFT,PEARL RIVER MOUTH BASIN,SOUTH CHINA SEA: EVIDENCE FOR HYDROTHERMAL ACTIVITY ASSOCIATED WITH PETROLEUM MIGRATION AND ACCUMULATION

Condensates are present in the PY30–1 structure in the Panyu Uplift, Pearl River Mouth Basin. Biomarkers and compound‐specific stable carbon isotope ratios of three condensate and two source rock samples indicate that the condensates were generated by lacustrine mudstones and coals in the Oligocene Enping Formation with a minor contribution from mudstones in the Eocene Wenchang Formation. Elevated vitrinite reflectance values, high smectite‐illite transformation ratios, and elevated fluid inclusion homogenization temperatures (about 100®C higher than normal borehole temperatures) point to the influence of hydrothermal fluids at the PY30–1 structure. Hydrocarbon migration was found to have occurred at the same time as hydrothermal activity. Modelling of formation pressure evolution in the Wenchang and Enping Formation source rocks in the Baiyun Depression, adjacent to the south of the Panyu Uplift, suggest that there were three episodes of overpressure release at approximately 40–37 Ma, 33–31 Ma and 16–10 Ma. Overpressure release was probably induced by uplift and erosion during the Zhuqiong, Nanhai and Dongsha phases of tectonic deformation, respectively. The third episode of overpressure release coincided with the main phase of hydrocarbon migration. The accumulation of condensates at the PY30–1 structure probably followed hydrocarbon expulsion from source rocks as a result of overpressure release in the adjacent Baiyun Depression. Vertical migration into overlying reservoir rocks occurred through faults associated with a fluid diapir which is present at the core of the PY30‐I structure. The faults are pathways along which petroleum can migrate up to shallow reservoirs.     

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN,NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations. In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded. In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations. Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.