南亚地区油气地质综合研究与区域优选

南亚地区经历冈瓦纳陆内裂陷、冈瓦纳大陆破裂与被动陆缘演化和印度板块与欧亚板块碰撞阶段,形成四大类沉积盆地,包括周缘前陆盆地、被动大陆边缘盆地、大陆裂谷盆地和克拉通盆地。含油气盆地主要分布在印度大陆的东缘和西缘,具有良好的油气地质条件,在层位上集中分布在古近系、新近系和白垩系。盆地类型与演化决定了油气富集规模和时代,有效烃源岩分布控制了油气田的平面分布,储盖组合控制了油气的纵向分布。根据盆地类型和规模、盆地石油地质条件、资源总量和盆地勘探程度等指标对南亚地区沉积盆地进行综合评价,优选出Bombay盆地、Indus盆地、Krishna—Godavari盆地、Bengal盆地、Assam盆地、Cambay盆地、Cauvery盆地、Potwar盆地等有利沉积盆地。     

松辽盆地陆相生油特征

引言松辽盆地是我国东北部的一个大型中新生代陆相沉积盆地,成北北东向展布,面积26万平方公里。自晚侏罗世到新生代,盆地经历了断陷、拗陷、上升三个阶段。它是在侏罗纪断陷盆地沉积的基础上,由于地壳的长期拗陷,大面积快速沉降,堆积了一套以砂泥岩为主的碎屑岩,并夹有油页岩及少量的生物灰岩,鲕状灰岩、泥灰岩、白云岩等。     

澳大利亚北卡那封盆地油气地质特征及勘探潜力分析

北卡那封盆地是澳大利亚最主要的产油气盆地,也是世界上主要的富气盆地之一。盆地经历了裂前、早期裂谷、晚期裂谷和裂后被动大陆边缘发育阶段,充填了以中生界占绝对优势的厚约15 km的沉积层系。三叠系—下白垩统内发育了4套烃源岩,油气主要储于上三叠统、上侏罗统和下白垩统。区域上,石油绝大部分分布于巴罗—丹皮尔次盆地,而滦金台地和埃克斯茅斯高地则富集了大部分的天然气和凝析油。截至2004年底,盆地内已发现石油(包括凝析油)5.27×108t,天然气28 424×108m3。油气地质综合分析表明该盆地仍具有良好的勘探前景,勘探程度中等的埃克斯茅斯高地、埃克斯茅斯次盆地和比格尔次盆地的勘探潜力最大。      

延吉盆地石油地质特征初探

延吉盆地在晚华为西期白岗质花岗岩为主的基底上广泛接受了以白垩系为主的中新生代沉积,最大厚度3900m。该盆地具有良好的生、储、盖配置关系和圈团条件。下白垩统大砬子组最厚达2000m。其中暗色泥岩发育,有机质丰度高,转化程度好,是好—较好生烃岩;砂层占地层总厚50％以上,是物性较好的储层;泥岩段横向分布较稳定,是良好的区域盖层。圈团类型主要为岩性、地层圈团,其次为披覆构造和断块圈团。盆地主要勘探目的层是大砬子组,有利远景区为朝阳川凹陷,其次为清茶馆凹陷和德新凹陷,有希望获得中小型油气田。     

Tar sand occurrence: Implications on hydrocarbon exploration in the offshore Benin Basin

The Benin Basin, just like other marginal basins in the Gulf of Guinea, evolved in the Cretaceous following the opening of the Atlantic. These other basins have recorded significant oil and gas discoveries offshore unlike the Benin Basin that has records of only large tar sand deposits onshore. A review of key play elements of the basin is carried out to assess the possible occurrence of oil and gas in its offshore part. The basin holds a high prospect for both oil and gas in the offshore with the oil kitchens probably occurring within the lower to upper Cretaceous sediments. Besides containing shales deposited during the world-wide Turonian anoxic event that could serve as source rock, the Turonian sequences also have shelf to slope deposits, which are likely to be turbidite of deep-water environments. These turbidites could serve as an excellent reservoir in the basin. Several thick shale sequences within the Cretaceous to Tertiary could provide enough seal for hydrocarbons. In addition, unconformity surfaces marked by reflection terminations that are very significant during pre-drift and syn-rift tectono-stratigraphic development of the basin point to existence of stratigraphic traps in the basin. Concentration of these petroleum elements within the Cretaceous sequences suggest that exploration efforts should be geared toward the Cretaceous, particularly the Turonian sequences in the basin.     

南海万安盆地油气充载系统特征

万安盆地位于我国南沙海域西南部 ,是一个新生代含油气盆地。盆地沉积层为上始新统—第四系 ,其最大厚度达 12 0 0 0 m。勘探成果证实该盆地具有良好的油气勘探前景。在盆地油气地质特征研究和油气源分析的基础上 ,确定了盆地含油气系统 ,并应用盆地模拟成果研究了盆地充载系统的特征及其与油气藏分布的关系     

蒙古尼尔金盆地石油地质特征及勘探前景

位于蒙古国中部的尼尔金盆地是一个中生代裂谷盆地，目前仍处于勘探早期。盆地内下白垩统湖相泥岩和纸状页岩具有很强的生油能力，下白垩统的煤系地层及上二叠统-下侏罗统中富含有机质的泥岩和煤层是可能的气源岩；盆地内广泛分布着3套储集层；上侏罗统、下白垩统、上白垩统的泥岩是潜在的盖层；存在多种生储盖组合及远景圈闭类型。通过对石油地质条件的分析，认为尼尔金盆地很可能形成多套含油气层系和多种油气藏类型，推测在盆地中部和南部会有大的油气藏存在。     

DARWIN'S NAVIDAD EMBAYMENT, SANTIAGO REGION, CHILE, AS A MODEL OF THE SOUTHEASTERN PACIFIC SHELF

The sedimentary sequence of Darwin's Navidad embayment overlies a Carboniferous metamorphic basement, and was deposited in a NNW-striking basin, open toward the sea. The sediments formed in a temperate climate and consist of three marine sequences—Cretaceous, Eocene, and Miocene-Pliocene. They exihibit some potential for oil and gas. The uppermost sediments of the Navidad Group were deposited in a more extensive sea, which was deeper, with lower wave energy. Near the present Pacific coastline, the sediments are tectonically disturbed. Farther east-and northward, the sediments are not affected by great disturbances. Some good types of stratigraphical traps, such as eolian sand beaches, may be expected.
Key Idea:The model adopted here is considered as one potential basin model for petroleum exploration in the southeastern Pacific shelf, where six or more NNW-striking open embayments are present.     

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.     

PETROLEUM SYSTEMS OF THE WEST IBERIAN MARGIN: A REVIEW OF THE LUSITANIAN BASIN AND THE DEEP OFFSHORE PENICHE BASIN

The relatively well‐studied Lusitanian Basin in coastal west‐central Portugal can be used as an analogue for the less well‐known Peniche Basin in the deep offshore. In this paper the Lusitanian Basin is reviewed in terms of stratigraphy, sedimentology, evolution and petroleum systems. Data comes from published papers and technical reports as well as original research and field observations. The integration and interpretation of these data is used to build up an updated petroleum systems analysis of the basin. Petroleum systems elements include Palaeozoic and Mesozoic source rocks, siliciclastic and carbonate reservoir rocks, and Mesozoic and Tertiary seals. Traps are in general controlled by diapiric movement of Hettangian clays and evaporites during the Late Jurassic, Late Cretaceous and Late Miocene. Organic matter maturation, mainly due to Late Jurassic rift‐related subsidence and burial, is described together with hydrocarbon migration and trapping. Three main petroleum systems may be defined, sourced respectively by Palaeozoic shales, Early Jurassic marly shales and Late Jurassic marls. These elements and systems can tentatively be extrapolated offshore into the deep‐water Peniche Basin, where no exploration wells have so far been drilled. There are both similarities and differences between the Lusitanian and Peniche Basins, the differences being mainly related to the more distal position of the Peniche Basin and the later onset of the main rift phase which was accompanied by Early Cretaceous subsidence and burial. The main exploration risks are related to overburden and maturation timing versus trap formation associated both with diapiric movement of Hettangian salt and Cenozoic inversion.     

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.     

内蒙古西部巴彦浩特盆地的构造特征及其演化

这是一个叠置在不同结晶基底上的中、新生代断陷盆地。中元古—早古生代时,西北部隆起,南部位于祁连海槽的被动大陆边缘,东部为坳拉槽。晚古生代南部为前渊,东部为碰撞谷。二叠、三叠纪时全区大面积隆起。侏罗纪发生裂陷形成分隔的许多小盆地,早白垩世才形成统一的盆地,之后即开始隆升。盆内构造以正断层为主,伴生滚动背斜;南部有少量逆断层和挤压褶皱。石炭系是主要生油气层,因此,有较厚石炭系分布的东部和南部坳陷带的含油气远景最佳。     

PETROLEUM SYSTEMS OF THE BONGOR BASIN AND THE GREAT BAOBAB OILFIELD,SOUTHERN CHAD

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion-related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks. Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large-scale inversion anticlines in the Lower Cretaceous succession whilst underlying “buried hill” -type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs. The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in-place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn-rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day.     

秘鲁Ucayali盆地油气地质特征及勘探潜力分析

秘鲁Ucayali盆地是位于安第斯山山前的前陆盆地之一,盆地内发育多套储盖组合。盆地内主力烃源岩包括上三叠统—下侏罗统Pucara组和二叠系Ene组的泥岩;发育多套储层,包括白垩系Chonta,Vivian,Cushabatay,Agua Caliente和Raya组储层,以及下二叠统的Ene组砂岩层等;盖层条件良好。北部主要发育基底相关的逆冲断层,而在盆地的南部发育薄皮式的逆冲断层,盆地内已发现的油气田的圈闭类型主要是与逆冲断层相关的断背斜圈闭。北Ucayali次盆Pucara组生成的油气运移至该组地层的剥蚀面,充注至白垩系,但遭到后期造山运动的破坏,通过再次运移聚集成藏。南Ucayali次盆中处于高—过成熟阶段的二叠系Ene组泥岩生成的天然气运移至上覆的二叠系和白垩系储层中。北Ucayali次盆西部的逆冲—前渊带圈闭、Pucara组碳酸盐岩圈闭、二叠系圈闭,以及盆地东部白垩系中的地层岩性圈闭是该盆地4个重要的潜力勘探领域。      

吉尔吉斯阿莱依盆地含油气远景分析

阿莱依盆地是特提斯北缘盆地群中的一个，晚三叠世-古近纪与相邻的塔吉克盆地、塔里木盆地西南坳陷基本连通，中新世以后才成为分隔的周缘前陆盆地。该盆地现今面积约5500km^2，推测沉积岩最厚达8km，地层北薄南厚，推测南侧出露的地层为外来的推覆体，北侧出露的是原地体，其形成与帕米尔北地块由南向北俯冲有关。根据与相邻盆地的类比，结合该区十分有限的资料推测，阿莱依盆地可能存在2套成熟烃源岩(古近系暗色泥岩，白垩系灰岩、泥灰岩和泥岩)，可能发育的含煤侏罗系也是可能烃源岩；至少存在2套成藏组合(白垩系和古近系)，新近系也可能形成次生油气藏；油气藏类型主要是被断层复杂化的背斜油气藏，以带气顶的油藏或凝析气藏为主。1991年在盆地内阿莱依1号构造钻探的阿菜依-1井未发现油层，认为该井钻在油水过渡带，阿菜依1号构造可能是一个背斜油藏。图4表1参8     

HYDROCARBON POTENTIAL OF THE INTRACRATONIC OGADEN BASIN, SE ETHIOPIA

The intracratonic Ogaden Basin, which covers one-third of the Democratic Republic of Ethiopia, developed in response to a tri-radial rift system which was active during Late Palaeozoic to Mesozoic times. Thick Permian to Cretaceous sequences, which principally occur in the SW and central parts of the basin, have proved petroleum potential. Reservoir rocks are mainly Permian to Lower Jurassic sandstones (the Calub and Adigrat Formations), and Callovian limestones (the Upper Hamanlei Formation). Source rocks are organic-rich Permian, Lower Jurassic and Callovian-Oxfordian lacustrine and marine shales.
This paper reviews the petroleum geology of the Ogaden Basin and assesses potential exploration targets. Successful exploration can be expected in view of the recent discovery of the Calub gas and gas/condensate field, and the occurrence of significant shows in the centre of the basin together with seeps along the margin.     

THERMAL MATURATION HISTORY OF THE SIRTE BASIN, LIBYA

The high degree of thermal maturity observed in shallow sediments in the western part of the Sirte Basin, Libya, requires higher geothermal gradients and/or thicker overburden in the past than exist today.
The degree of thermal maturity of the Upper Cretaceous shales, the regional structure, and the subsidence history of the basin all indicate that over 3,000 m of section was removed from the western flank of the basin by uplift and erosion in the mid-Tertiary. Vitrinite reflectance values in wells suggest that gradients of 1.6FC/100 ft to 1.8FC/100 ft existed in the western region at the time of peak thermal activity, in contrast with a general basin average of 1.2 F/ l00ft     

孟加拉盆地油气分布特征及主控因素

孟加拉盆地是发育在印度次大陆东北角比较典型的残留洋盆地,其经历了裂陷期、裂后期和前渊期。在残留洋盆地形成阶段发育了最重要的生储盖组合,主要烃源岩是渐新统Jenam组和中新统Bhuban组页岩;主要储集层是中新统Surma群Bhuban组和Boka Bil组陆架到潮控三角洲砂岩;盖层主要为中新统—上新统的海相页岩,分布广泛;圈闭类型以背斜为主。孟加拉盆地以天然气为主,绝大部分气田平面上分布在Surma坳陷、Tangail凸起、Hatia坳陷和东部褶皱带。天然气富集层位主要位于中新统Bhuban组和Boka Bil组。气田的分布与残留洋盆地的形成密切相关,盆地演化控制了含气层系的发育,盆地结构控制了天然气的平面分布。今后勘探的重点为盆地东部Surma坳陷及周缘、Hatia坳陷和东部褶皱带,处于压力过渡带的Surma群砂岩储层应是油气勘探的重点层系。通过对孟加拉盆地演化、石油地质条件和油气分布特征以及天然气成藏规律和主控因素的研究,可为残留洋盆地油气勘探提供借鉴和参考。     

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.     

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.