IN‐RESERVOIR FRACTIONATION AND THE ACCUMULATION OF OIL AND CONDENSATES IN THE SURMA BASIN,NE BANGLADESH

Petroleum in the Surma basin, NE Bangladesh (part of the Bengal Basin) ranges from waxy crude oils to condensates. The origin and source rocks of these hydrocarbons were investigated based on the distributions of saturated and aromatic hydrocarbons in 20 oil samples from seven oil and gas fields. The relative compositions of pristane, phytane and adjacent n‐alkanes suggest that the source rock was deposited in a non‐marine setting. The abundance and similar distribution of biphenyls, cadalene and bicadinanes in most of the crude oils and condensates indicates a significant supply of higher‐plant derived organic matter to the source rocks. Maturity levels of the crude oils and condensates from the Surma basin correspond to calculated vitrinite reflectance (R_c) values of 1.0–1.3%, indicating hydrocarbon expulsion from the source rock at a comparatively high maturity level. The R_c values of oils from the Titas field in the southern margin of the Surma basin are relatively low (0.8–1.0%). Some oils were severely biodegraded. The similar distribution of diamondoid hydrocarbons in both biodegraded and non‐biodegraded oils indicated similar types of source rocks and similar maturity levels to those of oils from the Surma basin. The Oligocene Jenam Shale and/or underlying non‐marine deposits located at greater depths may be potential source rocks. The diversity of the petroleum in the Surma basin was likely due to evaporative fractionation, resulting in residual waxy oils and lighter condensates which subsequently underwent tertiary migration and re‐accumulation. Evaporative fractionation due to modification of the reservoir structure occurred during and after the Pliocene, when large‐scale tectonic deformation occurred in and around the Bengal Basin.     

SHALLOW HYDROCARBON INDICATIONS ALONG THE ALPINE THRUST BELT AND ADJACENT FORELAND BASIN: DISTRIBUTION AND IMPLICATIONS FOR PETROLEUM EXPLORATION

Shallow oil and gas shows are common in the Alpine thrust front (including the Flysch Zone) and the North Alpine Foreland Basin in Switzerland, southern Germany and Austria, but have not hitherto been evaluated systematically. In the vertically‐drained Vienna Basin and the easternmost part of the Flysch Zone, shallow oil and gas shows and seeps often coincide with deeper‐lying hydrocarbon accumulations, and gas shows occur along major faults – for example within the urbanised area of the city of Vienna. The number of gas shows decreases in the Vienna Basin away from (to the south of) the subcrop of the main thermogenic source rock (the Upper Jurassic Mikulov Formation); however shallow accumulations of microbial gas occur in that area. To the west, along the northern margin of the laterally‐drained North Alpine Foreland Basin, oil shows have been recorded in both Austria and Switzerland; microbial gas shows are common in addition to thermogenic hydrocarbons. Typically the shows form regional clusters along river valleys and occur above shallow gas accumulations. A Lower Oligocene organic‐rich interval represents the main source of oil / condensate and thermogenic gas in the Upper Austrian part of the North Alpine Foreland Basin, whereas the composition of oil shows within the Calcareous Alps to the south indicates the presence of mature Mesozoic source rocks within the Alpine nappes. This implies the presence of an additional, as‐yet untested petroleum system. Thermogenic gas, occurring in Permo‐Triassic evaporitic rocks in the Calcareous Alps, as well as microbial gas in younger sediments, has frequently been encountered during salt mining and tunnelling activities. A surprising discrepancy has been found in different parts of the study area between the number of hydrocarbon shows and the number of economic fields. Whereas the number of fields and shows are approximately in proportion in the Vienna Basin and the Austrian sector of the North Alpine Foreland Basin, shows appear to be “under‐represented” in Germany. By contrast in Switzerland, despite a high number of shows especially in the North Alpine Foreland Basin and the Jura fold‐and‐thrust belt, no economic production has been established to date. Future exploration will show whether this is due to poor reservoir/trap quality, or if undiscovered resources are in fact present. The presence of oil shows generated from Mesozoic and Oligocene source rocks in the SW German and Swiss parts of the North Alpine Foreland Basin suggests the occurrence of multiple petroleum systems; these systems should be delineated in future studies. Few surface seeps have been recorded in less populated parts of the study area such as the high Alps, possibly due to sampling bias. However, this bias does not explain the low frequency of recorded hydrocarbon shows in the German part of the North Alpine Foreland Basin. This may be because the geological setting there is in general less favourable for the migration of thermogenic gas into shallow reservoirs and its preservation in shallow traps.     

GEOCHEMISTRY OF CRUDE OILS,SEEPAGE OILS AND SOURCE ROCKS FROM BELIZE AND GUATEMALA: INDICATIONS OF CARBONATE‐SOURCED PETROLEUM SYSTEMS

This study reviews the stratigraphy and the poorly documented petroleum geology of the Belize‐Guatemala area in northern Central America. Guatemala is divided by the east‐west trending La Libertad arch into the North and South Petén Basins. The arch is the westward continuation of the Maya Mountains fault block in central Belize which separates the Corozal Basin in northern Belize from the Belize Basin to the south. Numerous petroleum seeps have been reported in both of these basins. Small‐scale oil production takes place in the Corozal Basin and the North and South Petén Basins. For this study, samples of crude oil, seepage oil and potential source rocks were collected from both countries and were investigated by organic geochemical analyses and microscopy. The oil samples consisted of non‐biodegraded crude oils and slightly to severely biodegraded seepage oils, both of which were generated from source rocks with similar thermal maturities. The crude oils were generated from marine carbonate source rocks and could be divided into three groups: Group 1 oils come from the North Petén Basin (Guatemala) and the western part of the Corozal Basin (Belize), and have a typical carbonate‐sourced geochemical composition. The oils correlate with extracts of organic‐rich limestones assigned to the Upper Cretaceous “Xan horizon” in the Xan oilfield in the North Petén Basin. The oils were generated from a single source facies in the North Petén Basin, but were charged from two different sub‐basins. Group 2 oils comprise crudes from the South Petén Basin. They have characteristics typical of carbonate‐sourced oils, but these characteristics are less pronounced than those of Group 1 oils. A mixed marine/lacustrine source facies deposited under strongly reducing conditions in a local kitchen area is inferred. Group 3 oils come from the Corozal Basin, Belize. A carbonate but also a more “shaly” source rock composition for these oils is inferred. A severely biodegraded seepage oil from Belmopan, the capital of Belize, resembles a nearby crude oil. The eastern sub‐basin in the North Petén Basin may potentially be the kitchen area for these oils, and for the seepage oils found in the western part of the Corozal Basin. The seepage oils from the Corozal and Belize Basins are moderately to severely biodegraded and were generated from carbonate source rocks. Some of the seepage oils have identical C_27–29 sterane distributions to the Group 2 oils, but “biodegradation insensitive” biomarker ratios show that the seepage oils can be divided into separate sub‐groups. Severely and slightly biodegraded seepage oils in the Belize Basin were probably almost identical prior to biodegradation. Lower Cretaceous limestones from the Belize Basin have petroleum generation potential, but the samples are immature. The kitchen for the seepage oils in the Belize Basin remains unknown.     

MULTIPLE PETROLEUM SYSTEMS IN TERTIARY EXTENSIONAL BASINS, EAST CHINA: A CASE STUDY OF THE GUNAN-FULIN BASIN

The Gunan-Fulin Basin, a small, extensional basin of Tertiary age, is located within the Shenglipetroleum "province" which structurally corresponds to the Jiyan megabasin in East China. The Lower Tertiary succession in the Gunan-Fulin Basin is dominated by the Eocene-lower Oligocene Shahejie Formation, which is divided into four members. Major source rocks are present in the Es3 Member (Eocene), and the Es 1 Member (Oligocene). Both units were deposited during lacustrine transgressions in the Early Tertiary. They are composed of dark, organic-rich mudstones and oil shales of lacustrine origin, and contain good quality Type I-II kerogen. The Es 1 source rock was deposited in a saline lake occasionally invaded by the sea, while the Es3 unit was laid down in a fresh-water lake.
The maturity and characteristics of these source rocks and the related crude oils can be distinguished on the basis of their biomarker contents. Es 1 source rocks and related oils are of relatively low maturity, while those of Es3 derivation are mature to highly-mature. There are therefore two separate petroleum systems in the Gunan-Fulin Basin — Eocene and Oligocene.
These petroleum systems are isolated hydraulically, and have independent migration pathways in which fault planes and unconformity surfaces play important roles. The distribution of oil accumulations in the two systems is different as a result of faulting. Oil from the Eocene source rocks is trapped in reservoirs which are distributed stratigraphically from the basement to the Tertiary, while oil from the Oligocene source rock is confined to Oligocene and Miocene reservoir rocks.
The existence of multiple petroleum systems is an important feature of Tertiary extensional basins in East China, and results from multiple phases of block faulting and a high geothermal gradient.     

准噶尔盆地腹部地区原油金刚烷化合物特征及应用

利用色谱/质谱/质谱方法分析了准噶尔盆地腹部地区原油中金刚烷化合物的含量，探讨了金刚烷参数指标在腹部地区原油类型划分和成熟度判识中的适用性。腹部地区原油中金刚烷类化合物含量较低，主要分布在（200~500）×10-6。利用金刚烷类化合物浓度指标能够有效划分原油的类型，金刚烷异构化指标能够有效判识原油的成熟度。腹部地区原油主要分为两大类:Ⅰ类原油为早期相对低熟原油，金刚烷类化合物含量低，单金刚烷含量相对较高，浓度指标A/1-MA比值分布在0.50~0.71，成熟度指标MAI值较小，在0.41~0.50之间，主要分布在远离生烃凹陷区域；Ⅱ类原油为晚期相对高熟油，金刚烷类化合物含量较高，1-甲基单金刚烷含量较高，A/1-MA比值分布在0.30~0.37，MAI值在0.52~0.69之间，主要分布在生烃凹陷内，其分布格局与油气运移方向一致，即晚期充注的原油驱动早期充注的原油向远离生烃凹陷处运移，证实了腹部原油运移方向为盆1井西凹陷向北运移。      

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.     

蒸发分馏作用对原油中金刚烷类化合物分布与组成的影响 ——以塔里木盆地库车坳陷羊塔克构造上的原油为例

借助于色谱和色谱—质谱分析技术,对塔里木盆地库车坳陷羊塔克构造上两组原油中烃类组成进行了系统分析,以研究蒸发分馏作用对金刚烷类化合物分布与组成特征的影响.轻烃分析结果表明,YT5和YT101井两组原油都经历了蒸发分馏作用的改造,其中上部储层产次生凝析油,而下部储层产经蒸发分馏作用改造的残留油.相似的甾、萜烷分布与组成表...     

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.     

GEOCHEMICAL EVALUATION OF CRUDE OILS FROM THE CARACARA AND TIPLE AREAS,EASTERN LLANOS BASIN,COLOMBIA: PALAEO BIODEGRADATION AND OIL MIXING

This study presents an organic geochemical characterization of heavy and liquid oils from Cretaceous and Cenozoic reservoir rocks in the Tiple and Caracara blocks in the eastern Llanos Basin, Colombia. Samples of heavy oil were recovered from the Upper Eocene Mirador Formation and the C7 interval of the Oligocene – Miocene Carbonera Formation; the liquid oils came from these intervals and from the Cretaceous Guadalupe, Une and Gachetá Formations. The heavy oil and most of the liquid oils probably originated from multiple source rocks or source facies, and showed evidence of biodegradation as suggested by the coexistence of n‐alkanes and 25‐norhopanes. The results indicate a close genetic relationship between the samples in the Carbonera (C7 interval), Mirador and Guadalupe Formation reservoirs. These petroleums are interpreted to result from at least two separate oil charges. An early charge (Oligocene to Early Miocene) was derived from marine carbonate and transitional siliciclastic Cretaceous source rocks as indicated by biomarker analysis using GC/MS. This initial oil charge was biodegraded in the reservoir, and was mixed with a later charge (or charges) of fresh oil during the Late Miocene to Pliocene. A relatively high proportion of the unaltered oil charge was recorded for heavy oil samples from the Melero‐1 well in the Tiple block, and is inferred to originate from Cenozoic carbonaceous shale or coaly source rocks. Geochemical parameters suggest that oils from the Gachetá and Une Formations are similar and that they originated from a source different to that of the other oil samples. These two oils do not correlate well with extracts from transitional siliciclastic source rock from the Upper Cretaceous Gachetá Formation in the Ramiriqui‐1 well, located in the LLA 22 block to the north. By contrast, one or more organofacies of the Gachetá Formation may have generated the heavy oil and most of the liquid oil samples. The results suggest that the heavy oils may have formed as a result of biodegradation at the palaeo oil‐water contact, although deasphalting cannot entirely be dismissed.     

南苏门答腊盆地构造演化对沉积演化及成藏条件的控制

南苏门答腊盆地是新生代弧后裂谷盆地,盆地的构造演化明显地控制了沉积演化和成藏条件。早始新世—早渐新世为同生裂谷早期,地堑和半地堑发育,以陆相沉积为主,前三角洲页岩为重要的烃源岩,冲积扇和辫状河砂砾岩为主要储层;晚渐新世盆地处于同生裂谷后期的早期,西南方的海侵使盆地中央为海相沉积,边缘为三角洲和河流相沉积,三角洲中的含煤页岩为主要烃源岩和重要盖层,河流—三角洲相砂岩是重要储层;早中新世为同生裂谷后期末,盆地以海相沉积为主,深海—半深海泥页岩、泥灰岩是重要烃源岩和区域性盖层,而储层主要是滨浅海的碳酸盐岩滩和生物礁灰岩;中中新世—上新世,盆地遭受挤压,发生海退,海相、陆相和海陆过渡相同时发育,滨浅海的海退砂岩是良好的储层,而三角洲相泥页岩是好的烃源岩和盖层。     

原油中金刚烷同系物同分异构体丰度差异及影响机制

塔里木盆地轮古地区原油主要受到了气洗与热裂解这2种次生作用影响，使得原油具有较高丰度的金刚烷组分。采用GC?MS?MS技术定量表征全油中的金刚烷系列化合物，分析了不同成熟度油样中各金刚烷及其同系物同分异构体的相对丰度，发现无论是金刚烷同分异构体还是金刚烷同系物之间，均表现出以下特征：成熟度较低的油样中仲碳位取代的金刚烷占优，而成熟度较高的原油中叔碳位取代的金刚烷较高。这表明原油中金刚烷同系物异构体的丰度差异可以作为区分油样成熟度的定性指标。从化学机理方面应用价键理论分析认为，仲碳位取代金刚烷异构体中1个sp³杂化轨道被C—H单键占据，叔碳位取代金刚烷异构体4个sp³杂化轨道均被C—C单键占据，所以叔碳位取代金刚烷的原子轨道重合度高，键能大，可能是金刚烷系列中甲基取代在叔碳位比在仲碳位的热稳定性更高的本质原因。同时随着金刚烷碳数增加，化合物饱和蒸气压递减的物理性质也解释了气洗作用对金刚烷系列化合物差异化富集的现象。     

GEOCHEMICAL CHARACTERISTICS AND THERMAL MATURITY OF OILS FROM THE THRACE BASIN (WESTERN TURKEY) AND WESTERN TURKMENISTAN

Crude oils in the Thrace Basin (western Turkey) and western Turkmenistan are believed to have been generated by a common Oligocene siliciclastic source rock. This widespread source rock extends over the area between western Turkey and the eastern South Caspian Basin. Oils from three Eocene reservoirs in the Thrace Basin and from four Pliocene reservoirs onshore western Turkmenistan were analyzed to investigate and compare their source-rock characteristics. In order to understand controls on the timing of hydrocarbon generation and source-rock maturation in both basins, the results of quantitative basin modelling were compared with those of geochemical analyses.
The results indicate that all the oil samples exhibit similar geochemical characteristics, such as IP13-IP20 acyclic isoprenoid, terpane, regular sterane, methylsterane, and dinosterane profiles. The low tricyclic/pentacyclic terpane ratios, low C₂₉ norhopane/C₃₀ hopane ratios and low diasterane/regular sterane ratios, and the presence of 18α (H)³⁰ oleanane and gammacerane further support a common source or source facies. Based on these observations, it is concluded that shallow-marine clastics of Oligocene age constitute source rocks in both basins.
The oils are of low maturity (Req(%) < 0.60), as indicated by their low ethylcholestane 20S/20S+20R, 17α (H), 21β (H)-bishomohopane 22S/22S+ 22R, and high 17β (H), 21α (H) moretane/17β (H), 21α (H) hopane ratios. However, oils from west Turkmenistan appear to be more mature than those from the Thrace Basin. This is consistent with their earlier generation, which resultedfrom the higher sedimentation rate and higher heating rate. Present-day reservoir depths and temperatures appear to play only a minor role in determining the oils' maturities.     

PETROLEUM GEOLOGY AND HYDROCARBON POTENTIAL OF THE GUBAN BASIN,NORTHERN SOMALILAND

The Guban Basin is a NW‐SE trending Mesozoic‐Tertiary rift basin located in northern Somaliland (NW Somalia) at the southern coast of the Gulf of Aden. Only seven exploration wells have been drilled in the basin, making it one of the least explored basins in the Horn of Africa – southern Arabia region. Most of these wells encountered source, reservoir and seal rocks. However, the wells were based on poorly understood subsurface geology and were located in complex structural areas. The Guban Basin is composed of a series of on‐ and offshore sub‐basins which cover areas of 100s to 1000s of sq. km and which contain more than 3000 m of sedimentary section. Seismic, gravity, well, outcrop and geochemical data are used in this study to investigate the petroleum systems in the basin. The basin contains mature source rocks with adequate levels of organic carbon together with a variety of reservoir rocks. The principal exploration play is the Mesozoic petroleum system with mature source rocks (Upper Jurassic Gahodleh and Daghani shales) and reservoirs of Upper Jurassic to Miocene age. Maturity data suggest that maximum maturity was achieved prior to Oligocene rift‐associated uplift and unroofing. Renewed charge may have commenced during post‐ Oligocene‐Miocene rifting as a result of the increased heat flows and the increased depth of burial of the Upper Jurassic source rocks in localised depocentres. The syn‐rift Oligocene‐Miocene acts as a secondary objective owing to its low maturity except possibly in localised offshore sub‐basins. Seals include various shale intervals some of which are also source rocks, and the Lower Eocene evaporites of the Taleh Anhydrite constitute an effective regional seal. Traps are provided by drag and rollover anticlines associated with tilted fault blocks. However, basaltic volcanism and trap breaching as a consequence of the Afar plume and Oligocene‐Miocene rifting of the Gulf of Aden cause considerable exploration risk in the Guban Basin.     

Organic geochemistry investigations of crude oils from Bayoot oilfield in the Masila Basin,east Yemen and their implication for origin of organic matter and source-related type

Thirteen crude oil samples from fractured basement reservoir rocks in the Bayoot oilfield, Masila Basin were studied to describe oil characteristics and to provide information on the source of organic matter input and the genetic link between oils and their potential source rock in the basin. The bulk geochemical results of whole oil and gasoline hydrocarbons indicate that the Bayoot oils are normal crude oil, with high hydrocarbons of more than 60%. The hydrocarbons are dominated by normal, branched and cyclic alkanes a substantial of the light aromatic compounds, suggesting aliphatic oil-prone kerogen. The high abundant of normal, branched and cyclic alkanes also indicate that the Bayoot oils are not biodegradation oils.The biomarker distributions of isoprenoid, hopane, aromatic and sterane and their cross and triangular plots suggest that the Bayoot oils are grouped into one genetic family and were generated from marine clay-rich source rock that received mixed organic matter and deposited under suboxic conditions. The biomarker distributions of the Bayoot oils are consistent with those of the Late Jurassic Madbi source rock in the basin. Biomarker maturity and oil compositions data also indicate that the Bayoot oils were generated from mature source rock with peak oil-window maturity.     

SOLID HYDROCARBONS IN PROTEROZOIC DOLOMITES,TAOUDENI BASIN,MAURITANIA

The Taoudeni Basin (Mauritania / Mali, West Africa) was formed as a result of pre‐ Pan‐African subsidence associated with rifting at the margins of the West African craton. Hydrocarbons in the Taoudeni Basin are derived from source rocks in the Meso‐Neoproterozoic Atar Group, which is composed of facies varying from stromatolite‐dominated carbonates to organic‐rich basinal shales. The stromatolitic carbonates are dolomitized and contain solid hydrocarbons (pyrobitumen). The pyrobitumen was formed in response to a Mesozoic hydrothermal event, with peak temperatures locally reaching 380°C, which resulted in hydraulic fracturing of the carbonates. Gas shows were recorded from these carbonates in the Abolag‐1 well and suggest that they may have potential as a reservoir rock. For this study, samples of Atar Group dolostones and black shales were collected from two localities in the Mauritanian part of the Taoudeni Basin and were analyzed by means of various geochemical and microscope‐based techniques including fluid inclusion analyses. The study suggests that Meso‐Neoproterozoic source rocks generated oil and gas during the Late Neoproterozoic – Early Palaeozoic. Later, in the Jurassic, a hydrothermal event caused in‐reservoir thermal cracking of the hydrocarbons to pyrobitumen and a second phase of gas generation and migration.     

GEOCHEMICAL CHARACTERIZATION OF LOWER TOARCIAN SOURCE ROCKS FROM NW GERMANY: INTERPRETATION OF AROMATIC AND SATURATED HYDROCARBONS IN RELATION TO DEPOSITIONAL ENVIRONMENT AND MATURATION EFFECTS

The characterization of crude oils in terms of source rock facies and depositional environment, as well as their maturity and alteration stage, is a crucial element in exploration studies. The present contribution has implications for oil‐oil and oil‐source rock correlations. In the past, numerous parameters have been used for this purpose most of which are based on the analysis of saturated and aromatic hydrocarbons (including sulphur aromatics) and also on stable isotope signatures and elemental compositions. Recently, molecular indicators based on dibenzothiophene (DBT), phenanthrene (PHE) and their methyl derivatives methyldibenzothiophene (MDBT) and methylphenanthrene, as well as pristane (PRI) and phytane (PHY), have also been proposed (Hughes et al., 1995). These studies have attempted to infer a crude oil's source rock facies and lithology, and to classify the source rock's depositional environment. In the present study, the above compounds have been quantified by solvent extraction, liquid chromatography and capillary gas chromatography in 98 core samples of the Lower Toarcian Posidonia Shale Formation, a source rock in NW Germany. Most samples, cored between depths of 7m and 70 m, came from the Hils Half‐Graben in the Lower Saxony Basin. With a few exceptions from one borehole, the samples were unweathered marls or calcareous shales. The rocks contained mainly marine organic matter (Type II kerogen), the thermal maturity of which ranged from early mature to postmature (corresponding to 0.48‐1.44% mean vitrinite reflectance), therefore encompassing the range over which effective petroleum generation had occurred. We found that the influences of organic matter type and maturity on the molecular distributions of the above compounds were not obvious when interpreted in terms of a DBT/PHE vs PRI/PHY diagram. However, Principal Component Analysis (PCA) of our data‐set showed that alkylphenanthrene concentrations are strongly controlled by maturity, while the concentrations of PRI, PHY, and 1‐MDBT display a distinct source effect.     

利用地震信息定量预测烃源岩热成熟度——以琼东南盆地乐东—陵水凹陷为例

琼东南盆地深水区钻测井数量少、钻遇层位浅和难以获取高精度地层速度,不利于有机质成熟度的预测。为此,本文从烃源岩镜质体反射率—孔隙度(Ro-Φ)预测模型建立和地层速度提取两个关键环节入手,形成了一套适用于琼东南盆地乐东—陵水凹陷的烃源岩成熟度地震定量预测方法:①采用研究区及邻区烃源岩Ro与Φ的乘方关系,建立了烃源岩Ro-Φ预测模型;②利用有色反演方法确定了相对速度分量与低频速度分量,再将相对速度分量与低频速度分量合成为频带适中的地震绝对速度。对比Ro-TTI方法与本文采用的Ro-Φ方法的烃源岩成熟度预测效果可知:前者预测有机质成熟度精度更高,适用于勘探程度较高的地区;后者主要基于地震、钻井和地质资料,可以从宏观上了解烃源岩的空间展布及生烃潜力,适用于勘探程度较低的地区。古近系烃源岩成熟度的地震定量预测结果表明,古近系烃源岩在凹陷中心部位成熟度较高,向四周逐步降低,表现为:古近系上部渐新统(陵水组、崖城组)烃源岩达到成熟—高成熟阶段,局部地区甚至达到过成熟阶段,现今及成藏期对本区供烃具有重要贡献,其中崖城组烃源岩生烃最为有利;下部始新统烃源岩在全区几乎处于过成熟阶段。     

塔里木盆地西南部皮山北新1井白垩系油气成因

皮山北新1井位于塔里木盆地麦盖提斜坡皮山北1号背斜构造高部位,该井在白垩系获得油气,但油气源存在较大争议。原油轻烃特征表明,该井原油具有Ⅰ型母质类型来源的特征;原油饱和烃特征表明,生烃母质以泥质岩为主,但与塔河、玉北奥陶系原油有一定差异。原油二维色谱分析表明,该井原油与玉北、塔河、巴楚泥盆系原油均位于海相泥页岩的范畴;原油碳同位素特征表明,该井原油母质类型差于玉北奥陶系及巴楚巴什托石炭系原油。该井原油成熟度高于玉北奥陶系原油。通过该井白垩系油气与其周缘塔西南4套主力烃源岩生标特征的对比,认为皮山北新1井白垩系原油主要来源于塔西南海相石炭系烃源岩;天然气生源母质类型与塔西南柯克亚气田类似,有侏罗系腐殖型有机质来源天然气的贡献。皮山北新1井白垩系新层系油气成因研究将有助于拓展塔西南中新生界碎屑岩油气勘探领域。      

ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS,ONSHORE NILE DELTA,EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C₂₉/C₂₇ sterane, diasterane/sterane, hopane/sterane and oleanane/C₃₀ hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C₃₂ homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta. A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ¹³ methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.