Bacterial methane in the Atzbach-Schwanenstadt gas field (upper Austrian Molasse Basin), Part II: Retracing gas generation and filling history by mass balancing of organic carbon conversion applying hydrogeochemical modelling

In the Austrian Molasse Basin bacterial methane gas accumulations occur in Upper Oligocene to early Miocene deepwater clastic sediments. Gas is produced from the Upper Puchkirchen Formation (Aquitanian) in the Atzbach-Schwanenstadt gas field.     

济阳坳陷孤北低潜山煤成气成藏条件及特征

以往济阳坳陷所探明的天然气几乎均为油型气,为了打开济阳坳陷煤成气勘探局面,通过研究已获煤成气流的孤北低潜山成藏特征,在综合运用录井、岩心、地化分析、测井及地震等资料基础上,分析构造演化特征,结果显示：孤北低潜山上古生界经历了印支期抬升剥蚀、燕山期中生界沉积后的抬升剥蚀等多次改造,至喜山期受埕南及孤北断层控制大幅沉降沉积后在馆陶组沉积时期开始大量二次生气;而埕南、孤北断层明化镇组沉积早期停止活动更为气藏的保存提供了保障,该低潜山气源充足、储层条件好、盖层条件优越,具有形成煤成气藏的条件。结果认为：本区气藏具有自生自储、上生下储和上生侧储3种运聚方式,除孤北低潜山的上古生界气藏之外,该区的下古生界风化壳和该区以南孤岛凸起的下古生界也是煤成气藏勘探的重要领域。     

Geochemical characteristics and isotopic reversal of natural gases in eastern Kopeh-Dagh,NE Iran

Natural gas samples from two gas fields located in Eastern Kopeh-Dagh area were analyzed for molecular and stable isotope compositions. The gaseous hydrocarbons in both Lower Cretaceous clastic reservoir and Upper Jurassic carbonate reservoir are coal-type gases mainly derived from type III kerogen, however enriched δD values of methane implies presence of type II kerogen related material in the source rock. In comparison Upper Jurassic carbonate reservoir gases show higher dryness coefficient resulted through TSR, while presence of C₁C₅ gases in Lower Cretaceous clastic reservoir exhibit no TSR phenomenon. Carbon isotopic values indicate gas to gas cracking and TSR occurrence in the Upper Jurassic carbonate reservoir, as the result of elevated temperature experienced, prior to the following uplifts in last 33–37 million years. The δ¹³C of carbon dioxide and δ³⁴S of hydrogen sulfide in Upper Jurassic carbonate reservoir do not primarily reflect TSR, as uplift related carbonate rock dissolution by acidic gases and reaction/precipitation of light H₂S have changed these values severely. Gaseous hydrocarbons in both reservoirs exhibit enrichment in C₂ gas member, with the carbonate reservoir having higher values resulted through mixing with highly-mature-completely-reversed shale gases. It is likely that the uplifts have lifted off the pressure on shale gases, therefore facilitated the migration of the gases into overlying horizons. However it appears that the released gases during the first major uplift (33–37 million years ago) have migrated to both reservoirs, while the second migrated gases have only mixed with Upper Jurassic carbonate reservoir gases. The studied data suggesting that economic accumulations of natural gas/shale gases deeper than Upper Jurassic carbonate reservoir would be unlikely.     

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands,Arctic Russia

A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window.     

Formation of low permeability reservoirs and gas accumulation process in the Daniudi Gas Field,Northeast Ordos Basin,China

The Daniudi Gas Field is a typical large-scale coal-generated wet gas field located in the northeastern Ordos Basin that contains multiple Upper Paleozoic gas-bearing layers and considerable reserves of gas. Based on integrated analysis of reservoir petrology, carbonate cement C–O isotope, geochemistry of source rocks and HC gas and numerical basin modeling, a comprehensive study focusing on the formation of low permeability reservoirs and gas generation process uncovers a different gas accumulation scene in Daniudi Gas Field. The gas accumulation discovered was controlled by the reservoir permeability reduction and gas generation process, and can be divided into two distinct stages by the low permeability reservoir formation time: before the low permeability reservoir formation, the less matured gas was driven by buoyancy, migrated laterally towards NE and then accumulated in NE favorable traps during Late Triassic to early Early Cretaceous; after the low permeability reservoir formation, highly matured gas was driven by excessive pressure, migrated vertically and accumulated in-situ or near the gas-generating centers during early to late Early Cretaceous. The coupling relationship between reservoir diagenetic evolution and gas generation process controlled on gas accumulation of the Daniudi Gas Field. This study will aid in understanding the gas accumulation process and planning further E&D of the Upper Paleozoic super-imposed gas layers in the whole Ordos Basin and other similar super-imposed low permeability gas layer basins.     

Reservoir quality along a homoclinal carbonate ramp deposit: The Permian Upper Dalan Formation,South Pars Field,Persian Gulf Basin

Permo-Triassic carbonate successions host some of the largest oil and gas reserves in the Arabian Plate, including the world's largest gas reservoirs of the Upper Dalan and the Kangan formations in the South Pars Gas Field, Persian Gulf Basin. Both formations are stratigraphically equivalent to the Upper Khuff Formation which has been long recognized as a major oil and gas reservoir in the Arabian Peninsula. The Permian Upper Dalan Formation is composed mainly of mixed carbonate-evaporite sequences that formed on a laterally continuous homoclinal carbonate ramp with significant variations in reservoir heterogeneity and quality. They can be grouped in 18 microfacies. High reservoir qualities are found within high-energy shoal environments with a tendency of the best reservoir quality to occur towards the basin in a mid-ramp setting. In contrast, low-energy tidal flat environments exhibit the poorest reservoir quality. Reservoir quality from lagoonal environments is diverse. Diagenesis has significantly affected reservoir properties by both enhancing and destroying original porosity and permeability. Bivariate plots of porosity and permeability values, combined with thin section petrography indicate that pore-filling “pervasive” and poikilotopic anhydrite cements had the greatest negative impact on the reservoir quality whereas dolomitization and dissolution of grains and cements played the most positive role. Two third-order sequence stratigraphic cycles link lithologies and depositional environments to sea-level fluctuations. HSTs are associated with better reservoir characteristics than TSTs.     

Organic geochemical study of source rocks and natural gas and their genetic correlation in the eastern part of the Polish Outer Carpathians and Palaeozoic–Mesozoic basement

Geochemical characteristics of organic matter in the profiles of Dukla, Silesian, Sub-Silesian and Skole units of the Polish Outer Carpathians and of the Palaeozoic–Mesozoic basement in the Dębica-Rzeszów-Leżajsk-Sanok area were established based on Rock-Eval, vitrinite reflectance, isotopic and biomarker analyses of 485 rock samples. The Oligocene Menilite beds have the best hydrocarbon potential of all investigated formations within the Dukla, Silesian, and Skole units. The Ordovician, Silurian, Lower Devonian and locally Middle Jurassic strata of the Palaeozoic–Mesozoic basement are potential source rocks for oil and gas accumulated in Palaeozoic and Mesozoic reservoirs. Thirty one natural gas samples from sandstone reservoirs of the Lower Cretaceous-Lower Miocene strata within the Outer Carpathian sequence and eight from sandstone and carbonate reservoirs of the Palaeozoic–Mesozoic basement were analysed for molecular and isotopic compositions to determine their origin. Natural gases accumulated both in the Outer Carpathian and the Palaeozoic–Mesozoic basement reservoirs are genetically related to thermogenic and microbial processes. Thermogenic gaseous hydrocarbons that accumulated in the Dukla and Silesian units were generated from the Menilite beds. Thermogenic gaseous hydrocarbons that accumulated in the Sub-Silesian Unit most probably migrated from the Silesian Unit. Initial, and probably also secondary microbial methane component has been generated during microbial carbon dioxide reduction within the Oligocene Menilite beds in the Dukla Unit and Oligocene-Lower Miocene Krosno beds in the Silesian Unit. Natural gases that accumulated in traps within the Middle Devonian, Mississippian, Upper Jurassic, and Upper Cretaceous reservoirs of the Palaeozoic–Mesozoic basement were mainly generated during thermogenic processes and only sporadically from initial microbial processes. The thermogenic gases were generated from kerogen of the Ordovician-Silurian and Middle Jurassic strata. The microbial methane component occurs in a few fields of the Dukla and Silesian units and in the two accumulations in the Middle Devonian reservoirs of the Palaeozoic–Mesozoic basement.     

Petroleum retention in the Mandal Formation,Central Graben,Norway

Upper Jurassic organic matter-rich, marine shales of the Mandal Formation have charged major petroleum accumulations in the North Sea Central Graben including the giant Ekofisk field which straddles the graben axis. Recent exploration of marginal basin positions such as the Mandal High area or the Søgne Basin has been less successful, raising the question as to whether charging is an issue, possibly related to high thermal stability of the source organic matter or delayed expulsion from source to carrier.The Mandal Formation is in part a very prolific source rock containing mainly Type II organic matter with <12 wt.-% TOC and HI < 645 mg HC/g TOC but Type III-influenced organofacies are also present. The formation is therefore to varying degrees heterogeneous. Here we show, using geochemical mass balance modelling, that the petroleum expulsion efficiency of the Mandal Formation is relatively low as compared to the Upper Jurassic Draupne Formation, the major source rock in the Viking Graben system. Using maturity series of different initial source quality from structurally distinct regions and encompassing depositional environments from proximal to distal facies, we have examined the relationship between free hydrocarbon retention and organic matter structure. The aromaticity of the original and matured petroleum precursors in the Mandal source rock plays a major role in its gas retention capacity as cross-linked monoaromatic rings act on the outer surface of kerogen as sorptive sites. However, oil retention is a function of both kerogen and involatile bitumen compositions. Slight variations in total petroleum retention capacities within the same kerogen yields suggest that texture of organic matter (e.g. organic porosity) could play a role as well.     

南沙海域礼乐盆地中生界油气资源潜力

位于南沙东部海域的礼乐盆地是一大型的中、新生代叠置盆地,其特有的地质背景及巨厚的中生代地层显示了其与南沙海域其他新生代沉积盆地的差异。盆地内发育的厚度超过4 000 m的中生代海相地层,主要包括了上侏罗统—下白垩统的滨—浅海相含煤碎屑岩或半深海相页岩、上三叠统—下侏罗统三角洲—浅海相砂泥岩和中三叠统深海硅质页岩等3套地层,展示出盆地具有良好的油气生成潜力。而早期位于华南陆缘、现今位于南沙东部海域的礼乐盆地中生界,完全具备了形成油气藏的基本石油地质条件,具有较为良好的油气资源潜力,其中生界油气资源勘探具有非常重要的意义,将成为我国海域油气勘探的一个重要新领域。     

Depositional environment and hydrocarbon source potential of the Oligocene Ruslar Formation (Kamchia Depression; Western Black Sea)

The Oligocene Ruslar Formation is a hydrocarbon source rock in the Kamchia Depression, located in the Western Black Sea area. Depositional environment and source potential of the predominantly pelitic rocks were investigated using core and cuttings samples from four offshore wells. In these wells the Ruslar Formation is up to 500 m thick. Based on lithology and well logs, the Ruslar Formation is subdivided from base to top into units I–VI. Dysoxic to anoxic conditions and mesohaline to euhaline salinities prevailed during deposition of the Ruslar Formation. Relatively high oxygen contents occurred during early Solenovian times (lower part of unit II), when brackish surface water favoured nannoplankton blooms and the deposition of bright marls (“Solenovian event”). Anoxic conditions with photic zone anoxia were established during late Oligocene times (units III and IV) and, probably, reflect a basin-wide anoxic event in the Eastern Paratethys during Kalmykian times. Organic carbon content in the Ruslar Formation is up to 3%. Autochthonous aquatic and allochthonous terrigenous biomass contribute to the organic matter. Relatively high amounts of aquatic organic matter occur in the lower part of the Ruslar Formation (units I and II) and in its upper part (unit VI). Diatoms are especially abundant in the lower part of unit VI. The kerogen is of type III and II with HI values ranging from 50 to 400 mgHC/gTOC. Units I and II (Pshekian, lower Solenovian) are characterized by a fair (to good) potential to produce gas and oil, but potential sources for gas and oil also occur in the Upper Oligocene units IV–VI.     

南海北部神狐海域天然气水合物分布的主控因素

针对天然气水合物沉积成矿因素不明确等问题,通过利用南海北部神狐海域的高分辨率三维地震、测井和岩心等资料,对晚中新世以来的地层进行了高分辨率层序划分和精细的沉积解释。从温压、沉积、构造等方面探讨了神狐海域天然气水合物分布的主控因素,认为：BSR上部附近处于水合物稳定温压范围内;粗粒沉积物有利于天然气水合物的富集;在含水合物层段内,孔隙度与天然气水合物饱合度成正比关系;滑塌体是天然气水合物赋存的有利相带;气烟囱形成过程中产生的断裂系统可为富含甲烷流体向上运移提供通道,并在其上部滑塌体富集成矿。因此,神狐海域具备天然气水合物成藏的优越条件,是天然气水合物勘探开发的有利区块。     

Source rocks and petroleum systems in the Hungarian part of the Pannonian Basin: The potential for shale gas and shale oil plays

The objectives of our study were to assess the thickness, lateral extent, organic richness and maturity of the potential source rocks in Hungary and to estimate the volumes of hydrocarbons generated, in order that potential shale gas and shale oil plays could be identified and characterised.The Upper Triassic Kössen Marl in south-west Hungary could represent the best potential shale gas/shale oil play, due to its high organic richness, high maturity and the presence of fracture barriers. The area of gas- and oil-generative maturity is around 720 km² with the unexpelled petroleum estimated to be up to 9 billion barrel oil-equivalent.The Lower Jurassic sediments of the Mecsek Mountains and under the Great Plain contain fair quality gas-prone source rocks, with low shale gas potential, except for a thin Toarcian shale unit which is richer in organic matter. The latter could form a potential shale gas play under the Great Hungarian Plain, if it is thicker locally.The Lower Oligocene Tard Clay in north-east Hungary could represent the second best potential shale oil play, due to its organic richness, favourable maturity and large areal extent (4500 km²) with around 7 billion barrel oil-equivalent estimated in-place volume of petroleum.Middle Miocene marine formations could represent locally-developed shale gas plays; they have fair amounts of organic matter and a mixture of type II/III kerogen, but their vertical and lateral variability is high.The Upper Miocene lacustrine Endrőd Marl contains less organic matter and the kerogen is mainly type III, which is not favourable for shale gas generation. The high carbonate and clay content, plus the lack of upper and lower fracture barriers would represent additional production challenges.     

Geochemical characteristics of tight gas and gas-source correlation in the Daniudi gas field,the Ordos Basin,China

The molecular composition, stable carbon and hydrogen isotopes and light hydrocarbons of the Upper Paleozoic tight gas in the Daniudi gas field in the Ordos Basin were investigated to study the geochemical characteristics. Tight gas in the Daniudi gas field displays a dryness coefficient (C₁/C_1–5) of 0.845–0.977 with generally positive carbon and hydrogen isotopic series, and the C₇ and C_5–7 light hydrocarbons of tight gas are dominated by methylcyclohexane and iso-alkanes, respectively. The identification of gas origin and gas-source correlation indicate that tight gas is coal-type gas, and the gases reservoired in the Lower Permian Shanxi Fm. (P₁s) and Lower Shihezi Fm. (P₁x) had a good affinity and were derived from the P₁s coal-measure source rocks, whereas the gas reservoired in the Upper Carboniferous Taiyuan Fm. (C₃t) was derived from the C₃t coal-measure source rocks. The molecular and methane carbon isotopic fractionations of natural gas support that the P₁x gas was derived from the P₁s source rocks. The differences of geochemical characteristics of the C₃t gas from different areas in the field suggest the effect of maturity difference of the source rocks rather than the diffusive migration, and the large-scale lateral migration of the C₃t gas seems unlikely. Comparative study indicates that the differences of the geochemical characteristics of the P₁s gases from the Yulin and Daniudi gas fields originated likely from the maturity difference of the in-situ source rocks, rather than the effect of large-scale lateral migration of the P₁s gases.     

The petroleum resource potential of the Bering Sea region

The Bering Sea sedimentary basin comprises the Bering Sea and the adjacent intermontane depressions on the continents. It includes the following subordinate sedimentary basins: the Norton; Bethel; Saint Lawrence; Anadyr; Navarin; Khatyrka; Saint George; Bristol; Cook Inlet; and Aleutian consisting of the autonomous Aleutian, Bowers, and Komandor basins. All of them exhibit significant geological similarity. The Middle and Upper Miocene terrigenous sequences, which are petroliferous through the entire periphery of the Pacific Ocean, are characterized by their high petroleum resource potential in the Bering Sea continental margin as well, which is confirmed by the oil and gas pools discovered in neighboring onshore lowlands. The younger (Pliocene) and older (up to Upper Cretaceous) sedimentary formations are also promising with respect to hydrocarbons. The integral potential oil and gas resources of the Bering Sea sedimentary basin, including the continental slopes, are estimated by the US Geological Survey to be 1120 × 10⁶ t and 965 × 10⁹ m³, respectively.     

Source rock characteristics and biostratigraphy of the Lower Silurian (Telychian) organic-rich shales at Akyaka, central Taurus region, Turkey

The Akyaka section in the central Taurus region in the southern part of Turkey includes the organic matter and graptolite-rich black shales which were deposited under dysoxic to anoxic marine conditions in the Early Silurian. A biostratigraphical analysis, based on graptolite assemblages, indicates that the sediments studied may well be referable to the querichi Biozone and early Telychian, Llandovery. A total of 15 samples have been subjected to Leco and Rock-Eval pyrolysis and graptolite reflectance measurements for determination of their source rock characteristics and thermal maturity. The total organic carbon content of the graptolite-bearing shales varies from 1.75 to 3.52 wt% with an average value of 2.86 wt%. The present Rock-Eval pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is inert kerogen. The measured maximum graptolite reflectance (G_Rmax %) values are between 5.04% and 6.75% corresponding to thermally over maturity. This high maturity suggests a deep burial of the Lower Silurian sediments resulting from overburden rocks of Upper Paleozoic to Mesozoic Upper Cretaceous and Middle-Upper Eocene thrusts occurred in the region.     

A new possible giant hydrocarbon generated formation: The Upper Triassic source rock in Southwestern Junggar Basin,NW China

The Triassic formation is a possible new giant hydrocarbon generated formation in Northwest China and Mid-Asia. Taking the Upper Triassic formation in the Sikeshu Sag in Junggar Basin as an example, based on the comprehensive analysis on the geochemical characteristics of the cores and the dark mudstone of the outcrops and reservoir formation conditions, we have evaluated the Upper Triassic source rocks by comparing with those in the Ulungu Depression, and reached the following findings. Firstly, the Upper Triassic formation is mainly composed of dark mudstone and sandy mudstone deposits, and the hydrocarbon source rock is mainly distributed in the middle and upper parts with a thickness range of 100–150 m and area of 3500 km². Secondly, the source rock, moderate in organic matter abundance (with TOC range of 1%–3%), has the material basis for hydrocarbon generation. Thirdly, the organic matter has high percentage of sapropelinite, and is dominated by type II₂. Fourthly, the degree of the thermal evolution is moderate, and the source rock with R_o higher than 0.7% has a distribution area of about 1800 km², providing the conditions of massive hydrocarbon generation. Fifthly, the source rock has great burial depth and wide distribution; the source rock with a R_o of higher than 0.7% and thickness of more than 100 m has an area of around 1400 km², implying huge resource potential. Sixthly, the next step exploration should focus on highly mature hydrocarbon generation central area in the Upper Triassic - Lower Jurassic in the east of the sag to search for and confirm favorable traps. The research findings have important reference value for promoting the resource status of, deepening the understanding of reservoir formation, and clarifying the exploration direction in the Sikeshu Sag and other periphery Mid-Asia areas.     

The Petrophysical Characteristics of Jurassic Reservoirs of the Coastal Mississippi Counties and Adjacent State Waters

The purpose of this study is the determination of petrophysical characteristics observable for Jurassic reservoirs in the study area; these characteristics are important for hydrocarbon production from those reservoirs. The study area consists of the three Mississippi coastal counties, Hancock, Harrison, and Jackson, and Mississippi's state waters offshore. The section of importance to this study is the Upper Jurassic, which is made up of, from oldest to youngest, the Norphlet Formation, Smackover Formation, Haynesville Formation (including a Frisco City-equivalent granite wash and the Buckner Anhydrite), and Cotton Valley Group. Within the study area only one Upper Jurassic gas field has been discovered. The Catahoula Creek field is located onshore in Hancock County in the western portion of the study area and is productive of gas from Cotton Valley sands below 19,000 ft. Well log and core data from dry exploratory holes in the study area were used to supplement the limited reservoir data at Catahoula Creek. Nine wildcat wells have penetrated the Jurassic in the study area, so the Jurassic wildcat drilling density is approximately one wildcat well per 290 mi2. Because of this lack of data in the study area, published information on the following Upper Jurassic fields in southwestern Alabama, both onshore and offshore, is included: Chunchula field (Smackover), Hatter's Pond field (Smackover), Hatter's Pond field (Norphlet), and Lower Mobile Bay Mary Ann field (Norphlet). Structurally, the three coastal counties and offshore state waters of Mississippi occupy the southern flank of the Wiggins Arch, an area of positive Paleozoic basement features, and the related Hancock Ridge. The Jurassic strati graphic section in the study area consists of more than 5,000 ft of clastics, evaporites, and carbonates at depths below 17,000 ft to 24,000 ft.     

UK onshore oil exploration, 1930–1964

The earliest attempts to find oil in Britain, dating from 1918–1922, based on anticlines flanking the Pennines, were largely unsuccessful. Renewal of exploration in the 1930s, aimed at a broader range of prospects, met with much criticism but went ahead after nationalization of the unknown and undiscovered oil resources (1934). The south of England ranked as first priority but the initial drilling of the new campaign carried out in 1935–1937 yielded only minor quantities of oil and gas. Attention was transferred in 1938 to Upper Palaeozoic prospects in the Midlands and north, resulting in small gas and oil discoveries in Scotland and Yorkshire, and discovery of a series of commerical oilfields in the Upper Carboniferous of Nottinghamshire. In the 1950s the first commercial discovery in the Jurassic was made at Kimmeridge in Dorset. Further Carboniferous discoveries were made in Nottinghamshire and Lincolnshire, and a series of fresh objectives defined by seismic reflection were drilled in the Mesozoic basin of southern England. This phase of exploration was terminated at the end of 1964 by adverse fiscal changes. Continuation of effective exploration operations remained uneconomic until the oil price rise in 1973.     

缅甸安达曼海域中部天然气成因与气源

位于主动大陆边缘的缅甸安达曼海域中部天然气资源丰富,成因多样。天然气成因类型直接影响勘探领域与方向的确定。通过气体组分、CH4和CO2碳同位素资料,对缅甸安达曼海域中部天然气成因类型及气源岩进行了判识。结果表明:上新统部分天然气具有较轻CH4碳同位素,为生物成因气,部分碳同位素较重的天然气属于热成因气;中新统及渐新统天然气CH4碳同位素均较重,属于热成因气;CO2碳同位素显示其存在无机、有机2种成因;此外,还存在少量生物气与热成因气或无机气的混源气。认为该区无机成因CO2与CH4共存体系通过基底断裂来源于地壳深部或上地幔;上新统生物气来自上新统未熟源岩;产于上新统、中新统热成因气,来源于上新统下部、中新统或渐新统上部等深层高-过成熟烃源岩。     

平湖油气田主断裂西部烃源评价及油源对比

平湖油气田主力含油气区位于平湖主断裂以东区域,油源主要来源于东部生烃凹陷的半封闭海湾暗色泥岩和煤层.公司于2011年11月在主断裂西部钻了一口探井XY井,目的是为探测主断裂西部含油气情况,扩大油气储量.结果钻遇油气层12m,测试获日产气14.66×104m3,日产油107.8 m3,取得了一定突破.为进一步评价西部含油气规模,钻后进行了油源对比研究,认为西部的油气主要是东部运移聚集的结果,西部源岩也有一定贡献.西部有形成一定规模油气藏的潜力.