油气运聚定量模拟技术现状、问题及设想

对于定量模拟技术的研发及应用,首先简要讨论初次运移(排烃),然后主要重点放在二次运移(烃类运移聚集)。关于初次运移,建议采用简单但争议少的方法计算排烃,其正确性由二次运移的模拟结果是否接近勘探实际来判别。关于二次运移,目前有4种运聚定量模拟技术:多相达西流法、流径法、混合法(多相达西流法+流径法)和侵入逾渗法。然而,这4个技术近10年来虽然各自有了较大的改进,但在克服各自的最大缺点问题上基本上没有突破:①多相达西流法虽有完整的时间模拟功能,但因受计算机资源所限而实用价值较差;②流径法和侵入逾渗法基本上没有时间模拟功能,即模拟对象通常仅是现今(0 Ma)的地质体,而能在关键时间(≠0 Ma)进行模拟尚在探索中;③由于混合法的实用价值主要来源于流径法,故严格来说混合法也基本上没有时间模拟功能。对于每一技术,概要介绍其技术背景、技术方法和应用效果;通过对比,指出各自的优缺点和适用条件,为未来研发提出改进方案。通过上述分析研究,提出了一个具有时间模拟功能的运聚定量模拟技术方案:在全时空的三维网格上,采用单相(水)达西流法技术计算超压,在数据稀少时采用流径法,在数据密集时采用侵入逾渗法。     

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.     

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN,OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile. Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 ^oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m². The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m². Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.     

IMPACT OF MAGMATISM ON PETROLEUM SYSTEMS IN THE SVERDRUP BASIN, CANADIAN ARCTIC ISLANDS, NUNAVUT: A NUMERICAL MODELLING STUDY

Numerical modelling is used to investigate for the first time the interactions between a petroleum system and sill intrusion in the NE Sverdrup Basin, Canadian Arctic Archipelago. Although hydrocarbonexploration has been successful in the western Sverdrup Basin, the results in the NE part of thebasin have been disappointing, despite the presence of suitable Mesozoic source rocks, migrationpaths and structural/stratigraphic traps, many involving evaporites. This was explained by (i) theformation of structural traps during basin inversion in the Eocene, after the main phase ofhydrocarbon generation, and/or (ii) the presence of evaporite diapirs locally modifying the geothermalgradient, leading to thermal overmaturity of hydrocarbons. This study is the first attempt at modellingthe intrusion of Cretaceous sills in the east‐central Sverdrup Basin, and to investigate how theymay have affected the petroleum system. A one‐dimensional numerical model, constructed using PetroMod9.0®, investigates the effectsof rifting and magmatic events on the thermal history and on petroleum generation at the DepotPoint L‐24 well, eastern Axel Heiberg Island (79°23′40″N, 85°44′22″W). The thermal history isconstrained by vitrinite reflectance and fission‐track data, and by the tectonic history. The simulationidentifies the time intervals during which hydrocarbons were generated, and illustrates the interplaybetween hydrocarbon production and igneous activity at the time of sill intrusion during the EarlyCretaceous. The comparison of the petroleum and magmatic systems in the context of previouslyproposed models of basin evolution and renewed tectonism was an essential step in the interpretationof the results from the Depot Point L‐24 well. The model results show that an episode of minor renewed rifting and widespread sill intrusionin the Early Cretaceous occurred after hydrocarbon generation ceased at about 220 Ma in theHare Fiord and Van Hauen Formations. We conclude that the generation potential of these deeperformations in the eastern Sverdrup Basin was not likely to have been affected by the intrusion ofmafic sills during the Early Cretaceous. However, the model suggests that in shallower sourcerocks such as the Blaa Mountain Formation, rapid generation of natural gas occurred at 125 Ma, contemporaneous with tectonic rejuvenation and sill intrusion in the east‐central Sverdrup Basin.A sensitivity study shows that the emplacement of sills increased the hydrocarbon generation ratesin the Blaa Mountain Formation, and facilitated the production of gas rather than oil.     

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA,NORTHERN SOMALIA,PART 2: HYDROCARBON POTENTIAL

Seismic reflection profiles and well data show that the Nogal Basin, northern Somalia, has a structure and stratigraphy suitable for the generation and trapping of hydrocarbons. However, the data suggest that the Upper Jurassic Bihendula Group, which is the main source rock elsewhere in northern Somalia, is largely absent from the basin or is present only in the western part. The high geothermal gradient (～35–49 °C/km) and rapid increase of vitrinite reflectance with depth in the Upper Cretaceous succession indicate that the Gumburo Formation shales may locally have reached oil window maturity close to plutonic bodies. The Gumburo and Jesomma Formations include high quality reservoir sandstones and are sealed by transgressive mudstones and carbonates. ID petroleum systems modelling was performed at wells Nogal‐1 and Kalis‐1, with 2D modelling along seismic lines CS‐155 and CS‐229 which pass through the wells. Two source rock models (Bihendula and lower Gumburo) were considered at the Nogal‐1 well because the well did not penetrate the sequences below the Gumburo Formation. The two models generated significant hydrocarbon accumulations in tilted fault blocks within the Adigrat and Gumburo Formations. However, the model along the Kalis‐1 well generated only negligible volumes of hydrocarbons, implying that the hydrocarbon potential is higher in the western part of the Nogal Basin than in the east. Potential traps in the basin are rotated fault blocks and roll‐over anticlines which were mainly developed during Oligocene–Miocene rifting. The main exploration risks in the basin are the lack of the Upper Jurassic source and reservoirs rocks, and the uncertain maturity of the Upper Cretaceous Gumburo and Jesomma shales. In addition, Oligocene‐Miocene rift‐related deformation has resulted in trap breaching and the reactivation of Late Cretaceous faults.     

HYDROCARBON ACCUMULATION PROCESSES IN THE YANGTAKE FOLDBELT,KUQA FORELAND BASIN,NW CHINA: INSIGHTS FROM INTEGRATED BASIN MODELLING AND FLUID INCLUSION ANALYSES

Abundant gas and condensate resources are present in the Kuqa foreland basin in the northern Tarim Basin, NW China. Most of the hydrocarbons so far discovered are located in foldbelts in the north and centre of the foreland basin, and the Southern Slope region has therefore been less studied. This paper focusses on the Yangtake area in the west of the Southern Slope. Basin modelling was integrated with fluid inclusion analyses to investigate the oil and gas charge history of the area. ID modelling at two widely spaced wells (DB‐1 and YN‐2) assessed the burial, thermal and hydrocarbon generation histories of Jurassic source rocks in the foreland basin. Results show that the source rocks began to generate hydrocarbons (R_o >0.5%) during the Miocene. In both wells, the source rocks became mature to highly mature between 12 and 1.8 Ma, and most oil and gas was generated at 5.3–1.8 Ma with peak generation at about 3 Ma. Two types of petroleum fluid inclusions were observed in Cretaceous and lower Paleocene sandstone reservoir rocks at wells YTK‐5 and YTK‐1 in the Yangtake area. The inclusions in general occur along healed microfractures in quartz grains, and have either yellowish or blueish fluorescence colours. Aqueous inclusions coexisting with both types of oil inclusions in Cretaceous sandstones in well YTK‐5 had homogenization temperatures of 96–128 °C and 115–135 °C, respectively. The integrated results of this study suggest that oil generated by the Middle Jurassic Qiakemake Formation source rocks initially charged sandstone reservoirs in the Yangtake area at about 4 Ma, forming the yellowish‐fluorescing oil inclusions. Gas, which was mainly sourced from Lower Jurassic Yangxia and Middle Jurassic Kezilenuer coaly and mudstone source rocks, initially migrated into the same reservoirs in the Yangtake area at about 3.5 Ma and interacted with the early‐formed oils forming blueish‐fluorescing oil inclusions. The migration of gas also resulted in formation of the condensate accumulations which are present at the YTK‐1 and YTK‐2 fields in the Yangtake area.     

INTEGRATION OF BIODEGRADATION AND MIGRATION OF HYDROCARBONS IN A 2D PETROLEUM SYSTEMS MODEL: APPLICATION TO THE POTIGUAR BASIN,NE BRAZIL

Biodegradation is probably the most important in‐reservoir alteration process and is responsible for the majority of the known heavy oil accumulations. In the present study, biodegradation processes were integrated within a forward basin and petroleum systems model applied to the Potiguar Basin, NE Brazil. This basin was chosen because it has been studied in detail and data from previous investigations are publically available. In order to account for processes occurring during the biodegradation of hydrocarbons, the evolution of fluid properties was simulated through time. In the model, a new approach was developed in order to determine the intensity of microbial activity and the evolution of the oil‐water contact, the zone within which biodegradation is confined. The numerical results obtained by applying the forward simulator to a 2D model of the Potiguar Basin fit the observed data concerning the composition and quality of the oil in a series of oilfields. These accumulations are located along the NE‐SW oriented “Carnaubais trend” and show progressive biodegradation along the migration path from the offshore kitchen area. Our results show that the biodegradation trend observed along the cross‐section can in general be explained by the fact that reservoirs are successively filled as a result of spilling from previous reservoirs, with continuous hydrocarbon degradation occurring within the reservoirs. This charge history resulted in differences in the composition of oils transported from upstream to downstream reservoirs, and in the evolution over time of the ratio between biodegradation and reservoir filling rates. Thus, in addition to residence time in the biodegradation temperature window, the rate of reservoir infill, the rate of oil degradation and the migration pathways are key factors controlling biodegradation. This study also demonstrates how the approach developed within our petroleum system simulator, which integrates both migration and biodegradation, may improve the assessment of oil quantity, quality and migration timing.     

THE PETROLEUM SYSTEM IN THE SANDINO FOREARC BASIN, OFFSHORE WESTERN NICARAGUA

The underexplored Sandino Basin (Nicaragua Basin/Trough) is located within the forearc area of western Nicaragua and NW Costa Rica. Exploration activity since 2004 has focussed on the onshore sector of the basin, and has included the first drilling campaign for over 30 years. Recent 2D basin modelling of the offshore sector together with organic geochemical studies has attempted to reassess the basin's petroleum potential. Geochemical data from the deepest offshore well indicate that Middle Eocene to Lower Oligocene sediments of the Brito Formation, as well as Upper Oligocene to Lower Miocene sediments of the Masachapa Formation, may have source rock potential. A third and perhaps more significant potential source rock interval is associated with the Lower Cretaceous black shales of the Loma Chumico Formation, which has been studied in the adjacent forearc area in NW Costa Rica (Tempisque Basin) and is inferred to be present in the Sandino Basin.
The thermal history of the forearc basin is controlled by the low basal heat flow (39 mW/m²). 2D modelling has shown that the Sandino Basin is thermally mature, resulting in the potential for hydrocarbon generation in organic-rich intervals in the Brito and Masachapa Formations. A petroleum-generating "kitchen" has tentatively been identified on a NE-SW seismic section which crosses the basin. Modelling suggests that this kitchen has been active from the Late Eocene until the present day, and that the main phases of petroleum generation in general coincide with phases of maximum subsidence in the Late Eocene, Late Oligocene and Plio-Pleistocene. Hydrocarbon migration most probably occurred from the deep basin towards the flanks. Significant volumes of petroleum may have been lost prior to the Late Miocene before the formation of a coastal flexure which can be recognised in the NE of the seismic profile.     

BURIAL,TEMPERATURE AND MATURATION HISTORY OF THE AUSTRAL AND WESTERN MALVINAS BASINS,SOUTHERN ARGENTINA,BASED ON 3D BASIN MODELLING

This paper presents a numerical petroleum systems model for the Jurassic‐Tertiary Austral (Magallanes) Basin, southern Argentina, incorporating the western part of the nearby Malvinas Basin. The modelling is based on a recently published seismo‐stratigraphic interpretation and resulting depth and thickness maps. Measured vitrinite reflectance data from 25 wells in the Austral and Malvinas Basins were used for thermal model calibration; eight calibration data sets are presented for the Austral Basin and four for the Malvinas Basin. Burial history reconstruction allowed eroded thicknesses to be estimated and palaeo heat‐flow values to be determined. Six modelled burial, temperature and maturation histories are shown for well locations in the onshore Austral Basin and the western Malvinas Basin. These modelled histories, combined with kinetic data measured for a sample from the Lower Cretaceous Springhill Formation, were used to model hydrocarbon generation in the study area. Maps of thermal maturity and transformation ratio for the three main source rocks (the Springhill, Inoceramus and Lower Margas Verdes Formations) were compiled. The modelling results suggest that deepest burial occurred during the Miocene followed by a phase of uplift and erosion. However, an Eocene phase of deep burial leading to maximum temperatures cannot be excluded based on vitrinite reflectance and numerical modelling results. Relatively little post‐Miocene uplift and erosion (approx. 50–100 m) occurred in the Malvinas Basin. Based on the burial‐ and thermal histories, initial hydrocarbon generation is interpreted to have taken place in the Early Cretaceous in the Austral Basin and to have continued until the Miocene. A similar pattern is predicted for the western Malvinas Basin, with an early phase of hydrocarbon generation during the Late Cretaceous and a later phase during the Miocene. However, source rock maturity (as well as the transformation ratio) remained low in the Malvinas Basin, only just reaching the oil window. Higher maturities are modelled for the deeper parts of the Austral Basin, where greater subsidence and deeper burial occurred.     

准噶尔盆地腹部侏罗系油气运移路径模拟

2019年在准噶尔盆地钻探的前哨2探井取得重大突破,预示着盆地腹部侏罗系具有广阔的勘探前景.腹部发育远源和次生油气藏,源与储之间距离大,油气运移路径决定了油气藏的分布.基于研究区侏罗系油气主要沿断裂垂向运移、沿砂体侧向运移的特点,制定了以三维地质建模、参数研究和模拟计算为核心的研究思路,提出了断面网格的三维地质建模方法...     

HYDROCARBON POTENTIAL OF MIDDLE JURASSIC COALY AND LACUSTRINE AND UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SOURCE ROCKS IN THE SØGNE BASIN,NORTH SEA

The Søgne Basin in the Danish‐Norwegian Central Graben is unique in the North Sea because it has been proven to contain commercial volumes of hydrocarbons derived only from Middle Jurassic coaly source rocks. Exploration here relies on the identification of good quality, mature Middle Jurassic coaly and lacustrine source rocks and Upper Jurassic – lowermost Cretaceous marine source rocks. The present study examines source rock data from almost 900 Middle Jurassic and Upper Jurassic – lowermost Cretaceous samples from 21 wells together with 286 vitrinite reflectance data from 14 wells. The kerogen composition and kinetics for bulk petroleum formation of three Middle Jurassic lacustrine samples were also determined. Differences in kerogen composition between the coaly and marine source rocks result in two principal oil windows: (i) the effective oil window for Middle Jurassic coaly strata, located at ～3800 m and spanning at least ～650 m; and (ii) the oil window for Upper Jurassic – lowermost Cretaceous marine mudstones, located at ～3250 m and spanning ～650 m. A possible third oil window may relate to Middle Jurassic lacustrine deposits. Middle Jurassic coaly strata are thermally mature in the southern part of the Søgne Basin and probably also in the north, whereas they are largely immature in the central part of the basin. HI_max values of the Middle Jurassic coals range from ～150–280 mg HC/g TOC indicating that they are gas‐prone to gas/oil‐prone. The overall source rock quality of the Middle Jurassic coaly rocks is fair to good, although a relatively large number of the samples are of poor source rock quality. At the present day, Middle Jurassic oil‐prone or gas/oil‐prone rocks occur in the southern part of the basin and possibly in a narrow zone in the northern part. In the remainder of the basin, these deposits are considered to be gas‐prone or are absent. Wells in the northernmost part of the Søgne Basin / southernmost Steinbit Terrace encountered Middle Jurassic organic–rich lacustrine mudstones with sapropelic kerogen, high HI values reaching 770 mg HC/g TOC and E_a‐distributions characterised by a single dominant E_a‐peak. The presence of lacustrine mudstones is also suggested by a limited number of samples with HI values above 300 mg HC/g TOC in the southern part of the basin; in addition, palynofacies demonstrate a progressive increase in the abundance and areal extent of lacustrine and brackish open water conditions during Callovian times. A regional presence of oil‐prone Middle Jurassic lacustrine source rocks in the Søgne Basin, however, remains speculative. Middle Jurassic kitchen areas may be present in an elongated palaeo‐depression in the northern part of the Søgne Basin and in restricted areas in the south. Upper Jurassic – lowermost Cretaceous mudstones are thermally mature in the central, western and northern parts of the basin; they are immature in the eastern part towards the Coffee Soil Fault, and overmature in the southernmost part. Only a minor proportion of the mudstones have HI values >300 mg HC/g TOC, and the present‐day source rock quality is for the best samples fair to good. In the south and probably also in most of the northern part of the Søgne Basin, the mudstones are most likely gas‐prone, whereas they may be gas/oil‐prone in the central part of the basin. A narrow elongated zone in the northern part of the basin may be oil‐prone. The marine mudstones are, however, volumetrically more significant than the Middle Jurassic strata. Possible Upper Jurassic – lowermost Cretaceous kitchen areas are today restricted to the central Søgne Basin and the elongated palaeo‐depression in the north.     

玛湖-盆1井西复合含油气系统低压特征与成因

随着油气勘探的不断深入，已在越来越多的沉积盆地中发现了低压现象，但对低压成因及其与油气运聚分布关系的研究则显得不足。玛湖-盆1井西复合含油气系统是准噶尔盆地油气分布最集中的地质单元，研究表明该系统地层中高压和低压均存在，侏罗系及以上地层中多低压，且在气藏分布区低压更突出，形成较开放性的压力系统。随着盆地的形成演化，异常地层压力亦有产生、发展和消亡的过程。玛湖-盆1井西复合含油气系统中低压的形成与油气运移过程中轻烃组分的漏失量大于油气和地下水的运移补给量，同时盆地抬升剥蚀和地温的持续下降，进而造成地层中能量亏损有关，而低压的形成时间则应该在古近纪。     

THE THERMAL GRADIENT HISTORY OF THE THRACE BASIN, NW TURKEY: CORRELATION WITH BASIN EVOLUTION PROCESSES

Thermal maturity modelling is widely used in basin modelling to help assess the exploration risk. Of the calibration algorithms available, the Easy%Ro model has gained wide acceptance. In this study, thermal gradients at 70 wells in the Thrace Basin, NW Turkey, were calibrated against vitrinite reflectance (%Ro) using the Easy%Ro model combined with an inverse scheme. The mean squared residual (MSR) was used as a quantitative measure of mismatch between the modelled and measured %Ro. A 90% confidence interval was constructed on the mean of squared residuals to assess uncertainty. The best thermal gradient (i.e. minimum MSR) was obtained from the MSR curve for each well, and an average palaeo‐thermal gradient map of the Thrace Basin was therefore created. Calculated thermal gradients were compared to the results of previous studies. A comparison of modelled palaeo‐thermal gradients with those measured at the present day showed that the thermal regime of the Thrace Basin has not changed significantly during the basin's history. The geological and thermal characteristics of the Thrace Basin were compared and the thermal anomalies were evaluated as a function of basin evolution processes. The basin's thermal regime was controlled by: (1) basement edge effects; (2) crustal thickness and basement heat flows; (3) thermal conductivity variations within the stratigraphic column; (4) transient heat flow effects; and (5) the influence of tectonic features. The impact of these factors on variations in the thermal gradients is discussed in detail. Basement edge effects are most marked on the steep northern margin of the basin where heat is preferentially retained in highly conductive basement rocks rather than being transferred into less conductive sedimentary rocks. Thus, heat is significantly focused onto the northern edge of the basement, resulting in a thermal anomaly along the northern basin margin. The margins of the basin, with relatively thick upper crust, have relatively higher thermal gradients compared to the central areas. This is due to radiogenic heat production in the upper crust. Thus, thermal gradients increase above highs and at the margins where thicker upper crust is present. A heat flow map of the Thrace Basin, constructed using a basin‐scale crustal thickness map and a basement heat‐flow algorithm, is presented and demonstrates the heat generation potential of the upper crust. The Eocene Ceylan Formation, which has relatively low thermal conductivity, significantly reduces the thermal gradients by blocking heat transferred from the basement. Areas of high sedimentation rate are associated with low thermal gradients due to the transient heat flow effects of young, thick and “thermally immature” sediments as a function of the heat capacities of these deposits. A direct relationship between thermal gradients and major structural trends could not be established because of a number of factors including the inactivity of the subsurface Miocene fault systems, which did not allow the flow of high temperature fluids through to shallow depths; also, the steady burial and sedimentation rates since the Early Eocene have maintained the pressure system in equilibrium.     

石油生运聚模拟系统的研制及其应用

盆地模拟是目前石油地质勘探的一项必备技术,但该技术还不很成熟,特别是在油气的二次运移和聚集量模拟上仍很薄弱。本文建立了一套石油生、运、聚模拟的地质模型、数学模型和模拟系统,特别是在排油量模拟、二次运移空间确定和石油渗漏量模拟等方面进行了比较深入的探讨。该系统通过在辽河盆地某油气田的实际应用,获得了满意的结果。     

HYDROCARBON HABITAT OF THE SEDANO TROUGH,BASQUE‐CANTABRIAN BASIN,SPAIN

This paper analyzes the hydrocarbon habitat and potential of the Sedano trough in the SW sector of the Basque‐Cantabrian Basin (northern Spain). The study is based on regional geological data, geochemical analyses, basin modelling simulations and play analysis techniques, and attempts to quantify by volumetric resource appraisal the volume of hydrocarbons generated, expelled and migrated from the main Sedano trough depocentre. A Lower Jurassic shale source rock has been identified and is responsible for the oil at Ayoluengo field, for the oil shows at the Polientes and Tozo wells, and for the Zamanzas and Basconcillos de Tozo tar sands which outcrop at the NE and SW margins of the Sedano trough respectively. Thermal history modelling indicates that petroleum generation and expulsion from the Lower Jurassic source rock started in the Sedano trough in the Early Cretaceous, with the main oil generation phase occurring in latest Cretaceous to Paleogene times. GC, GC‐MS and isotopic analyses of oils, tar sands and source rock extracts from the Sedano trough indicate good correlations between the Lower Jurassic source rock and the Ayoluengo oil, and tar sands from the basin margins. Petroleum plays and traps are abundant and are a result of a complex polyphase geological history. They can be grouped into:(i) early salt‐induced structural plays; (ii) later structural plays associated with a mid‐Tertiary compressional phase; and (iii) stratigraphic plays within the Upper Jurassic – Lower Cretaceous siliciclastic succession. A volumetric resource appraisal of the Lower Jurassic source rock indicates that a total of 11 billion bbl of oil could have been generated and expelled in the Sedano trough, and around 880 million bbl of oil have migrated into potential traps in 15 identified drainage areas. This results in a generation‐accumulation efficiency of 7%. Undiscovered resources have been estimated at 154 million bbl of oil, indicating that there is still moderate undiscovered hydrocarbon potential in the area.     

高含硫裂缝性气藏流体渗流规律研究进展

针对高含硫裂缝性气藏存在硫沉积、相态变化、吸附、扩散、非达西流动效应等复杂渗流特征以及H2S具有高腐蚀性、剧毒性的特点，从吸附和扩散理论、非达西渗流、耦合流动规律、相态理论研究、硫物化沉积规律、酸性气藏模拟发展等研究方面对国内外研究现状进行了分析和评价。提出了高含硫裂缝性气藏渗流规律研究发展方向和研究热点：采用物模和数模相结合的方法，实验研究确定高含硫裂缝气藏气-液-固运移机制、硫沉积地层伤害机理、以及测试H₂S及天然气混合物吸附特征和流体相态变化规律；理论研究建立双重介质流体相变与气-液-固耦合综合模型，研究分析硫物化沉积、非达西流动效应、气体吸附和扩散等因素对流体流动的影响。     

PREDICTING THE TIMING AND CHARACTERISTICS OF PETROLEUM FORMATION USING TAR MATS AND PETROLEUM ASPHALTENES: A CASE STUDY FROM THE NORTHERN NORTH SEA

The Northern Viking Graben area in the Norwegian North Sea was studied in order to investigate the petroleum formation characteristics of the Upper Jurassic Draupne Formation. In this area, the organofacies of the Draupne Formation, and consequently its petroleum generation characteristics, show significant variations. These variations represent a major risk, particularly in the context of basin modelling studies. Therefore, tar‐mat asphaltenes, oil asphaltenes and source‐rock samples from this area were studied in order to evaluate the use of migrated asphaltenes from petroleum reservoirs and tar mats in basin modelling. The samples were studied using bulk kinetic analysis, open‐system pyrolysis‐gas chromatography and elemental analyses, and the results were integrated into a basin modelling study. The results from these different sample materials were compared both to each other and to natural petroleum, in order to assess their significance for future petroleum exploration activities. We show that in cumulative petroleum systems, the transformation characteristics of the asphaltenes incorporate those of the individual source rock intervals which have contributed to the relevant reservoir system. Thus, the petroleum formation window predicted by the use of asphaltene kinetics is broad, and covers the majority of the formation windows predicted from the individual source rock samples. In addition, the molecular characteristics of asphaltene‐derived hydrocarbons show that compositional characteristics, such as aromaticity, correspond more closely to natural oils than to the respective source‐rock products. Our results confirm that the heterogeneous nature of the Draupne Formation results in a significantly broader petroleum formation window than is conventionally assumed. We propose that oil and tar‐mat asphaltenes from related reservoirs represent macromolecules which account for this heterogeneity in the source rock, since they represent mixtures of charges from the different organofacies. One conclusion is that the use of oil and tar‐mat asphaltenes in kinetic studies and compositional predictions may significantly improve definitions of petroleum formation characteristics in basin modelling.     

松辽盆地东岭地区幕式成藏分析

油气运聚期次、成熟度分析是一项非常有价值的研究工作。利用有机包裹体测温和包裹体中烃类组成特征、结合盆地模拟技术的精细时-温埋藏史、古地温史恢复来研究油气运聚期次、成熟度,可有效地指明成藏史。作者对松辽盆地南部东岭地区有机包裹体测温和包裹体中烃类组成的研究表明,油气运聚具有3期幕式成藏的特点:第一期为85.8Ma(姚家组沉积末期);第二期为78.6Ma(嫩江组沉积末期);第三期为66Ma(明水组沉积末期)。由于有机包裹体丰度及有机组分含量较低,加之后期构造破坏,不利于现今的油气勘探。      

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of R_o = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (R_o 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.