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.     

SOURCE-ROCK EVALUATION AND BASIN MODELLING IN NE EGYPT (NE NILE DELTA AND NORTHERN SINAI)

The area comprising the NE Nile Delta and adjacent northern Sinai is an important hydrocarbon province in Egypt, but the origin of the hydrocarbons and their migration is not fully understood. In this paper, we evaluate organic source facies and assess the results of basin modelling in order to improve our understanding of the regional petroleum system.
Organic-geochemical and petrographic analyses of 800 rock samples ranging in age from Early Jurassic to Pleistocene were used in this study. Most of the samples studied had moderate to high TOC contents, and kerogen was a mixture of Types II and III with a wide range of petroleum generation potentials from very poor to very good. Thermal and burial history models indicate that the source rocks entered the early-mature/mature stage in very recent times (Pleistocene to Recent). The top of the oil window ranges in depth from 1,800 m to 4,500 m, whereas the bottom of the oil window was not reached by most of the studied wells.
In combination with numerical modelling results, structure contour maps for key horizons reveal possible migration trends and prospective areas. We tentatively identify prospective targets for hydrocarbon exploration, both in the Tertiary sequence and in the Cretaceous succession, especially where carbonate build-ups are present.     

低渗、特低渗边际油田的油藏地质及开发特征——以辽北中生代盆地陆相油田为例

边际油田是陆相地层中常见的一种油田类型,因油田储量小、油藏能量低、储层质量差等不利因素,使得开发这类油田遇到许多困难。近年来发现辽北及内蒙中生代盆地(上侏罗统)存在众多陆相低渗、特低渗边际油田,马家铺、廖1块和白3-白4块3个低渗、特低渗油田就是典型代表。本文重点讨论此类边际油田的储层特征,分析储层低渗的原因,并总结低渗油田的油藏动力学特征,在此基础上指出了合理开发边际油田的对策。     

GENETIC CLASSIFICATION OF OIL FAMILIES IN THE CENTRAL AND SOUTHERN SECTORS OF THE GULF OF SUEZ,EGYPT

The results of geochemical analyses were used to classify ten oil samples from six fields in the central and southern sectors of the Gulf of Suez, Egypt. The samples were collected from sandstone pay‐zones ranging in age from Early Palaeozoic (Nubia‐C) to Miocene (Kareem Formation) at various present‐day depths. Molecular and stable isotope analyses indicate the presence of two genetic oil families (Families I and II) and suggest their probable source rocks. The biomarker characteristics of Family 1 oils include low Pr/Ph ratio, CPI < 1.0, depleted rearranged steranes, very low diahopane concentrations, high sulphur content, high metal content and V/Ni ratio, low oleanane index, abundance of gammacerane and C₂₇ steranes, and high relative abundance of homohopanes and C₃₀ 24‐n‐propylcholestanes. Source rock deposition took place under anoxic marine‐carbonate and hypersaline conditions. The NCR and NDR 24‐norcholestane ratios together with the presence of highly‐branched isoprenoids in this oil family are consistent with Upper Cretaceous – Lower Paleogene source rocks. These characteristics suggest that the Upper Cretaceous Duwi Formation/Brown Limestone or Lower Eocene Thebes Formation are the source rocks for the oils in this family, which occur in the central sector of the Gulf of Suez. Family II oils have geochemical characteristics that point to a mature source rock deposited in a weakly reducing or suboxic setting under normal salinity conditions. Abundant oleananes, high 24‐ to 27‐norcholestane ratios and abundant C₂₅ highly‐branched isoprenoids suggest a Paleogene source rock. The Lower Miocene Rudeis Formation is the best candidate to have generated these oils which occur in the southern sector of the Gulf of Suez.     

昌参2井九佛堂组原油的地球化学特征及油源对比

根据昌参 2井 2 0 1 0 8m和 2 0 1 5m两个含油样品多项地球化学分析资料综合判断 ,上侏罗统九佛堂组原油属于成熟原油 ,具有六高、七低、一轻的地球化学特征。应用本井各组段油、岩族组成 ,饱和烃色谱 ,甾、萜生物标志物 ,碳同位素等项资料数据对比结果 ,认为该原油与阜新组、沙海组及九佛堂组下部烃源岩不相关 ,而与九佛堂组上部湖相烃源岩有良好的亲缘关系 ,属于自生自储 ,短距离运移聚集而成     

CRUDE OIL GEOCHEMISTRY AND SOURCE ROCK POTENTIAL OF THE UPPER CRETACEOUS – EOCENE SUCCESSION IN THE BELAYIM OILFIELDS,CENTRAL GULF OF SUEZ,EGYPT

This study evaluates the petroleum potential of source rocks in the pre‐rift Upper Cretaceous – Eocene succession at the Belayim oilfields in the central Gulf of Suez Basin. Organic geochemical and palynofacies investigations were carried out on 65 cuttings samples collected from the Thebes, Brown Limestone and Matulla Formations. Analytical methods included Rock‐Eval pyrolysis, Liquid Chromatography, Gas Chromatography and Gas Chromatography – Mass Spectrometry. Four crude oil samples from producing wells were characterised using C₇ light hydrocarbons, stable carbon isotopes and biomarker characteristics. The results showed that the studied source rocks are composed of marine carbonates with organic matter dominated by algae and bacteria with minimal terrigenous input, deposited under reducing conditions. This conclusion was supported by n‐alkane distributions, pristane/ phytane ratios, homohopane and gammacerane indices, high concentrations of cholestane, the presence of C₃₀ n‐propylcholestanes, and low diasterane ratios. The source rocks ranged from immature to marginally mature based on the Rock‐Eval T_max together with biomarker maturity parameters. The analysed crude oil samples are interpreted to have been derived from source rock intervals within the Eocene Thebes Formation and the Upper Cretaceous Brown Limestone. The similarity in the geochemical characteristics of the crude oils suggests that there was little variation in the organofacies of the source rocks from which they were derived.     

苏北盆地阜三段油气成藏规律

阜三段成油气组合是苏北盆地近年增储上产的主要目的层系.该盆地阜二段中下部半咸水相优质烃源岩是阜三段成藏的主力烃源岩,有利储层则位于阜三段上砂组及阜三段下砂组的上部,与阜二段中下部烃源岩之间夹着厚层生烃能力极差的湖相泥岩,使其生储盖配套性较差,必须依靠断层沟通.受此控制,阜三段油气成藏具明显部位性,主要发育于继承性鼻状隆起带及同生断裂或大型晚期断裂附近.有利的构造格式类型、沉积体系与构造格局、圈闭体的有机配置则是形成阜三段油气藏的必备要素.阜三段油气成藏模式表明,在生储配置不利的区块,应重点围绕继承性隆起带及同生断层或大型晚期断层开展油气勘探.      

松辽盆地主要断陷大中型油气田形成分布特征

在松辽盆地深部发育的30多个中生界断陷中,已发现的大中型油气田主要分布于贯穿盆地中央区域的北北东向孙吴—双辽岩石圈断裂两侧的徐家围子、十屋、长岭等3个富油气深断陷之中。这些深断陷的成油气地质条件和大中型油气田分布规律研究表明,大中型油气田分布在箕状深断陷生烃中心周缘发育的中央断垒带、缓坡坡折带、缓坡坡垒带、陡坡坡折带上的一批近东西向继承性鼻状隆起构造与地层超覆尖灭、岩性复合圈闭之中,其中,2个深断陷之间的中央隆起带往往是大型油气田的分布区域。为进一步发现大中型油气田,下一步应该围绕富油气深断陷的上述有利区带展开深度勘探。     

MATURITY AND PETROLEUM SYSTEMS MODELLING IN THE OFFSHORE ZAMBEZI DELTA DEPRESSION AND ANGOCHE BASIN,NORTHERN MOZAMBIQUE

Petroleum systems analysis and maturity modelling is used to predict the timing and locations of hydrocarbon generation in the underexplored offshore Zambezi Delta depression and Angoche basin, northern Mozambique. Model inputs include available geological, geochemical and geophysical data. Based on recent plate‐tectonic reconstructions and regional correlations, the presence of Valanginian and Middle and/or Late Jurassic marine source rock is proposed in the study area. The stratigraphy of the Mozambique margin was interpreted along reflection seismic lines and tied to four wells in the Zambezi Delta depression. Thermal maturity was calibrated against measured vitrinite reflectance values from these four wells. Four 1‐D models with calibration data were constructed, together with another five without calibration data at pseudo‐well locations, and indicate the maturity of possible source rocks in the Zambezi Delta depressions and Angoche basin. Two 2‐D petroleum systems models, constrained by seismic reflection data, depict the burial history and maturity evolution of the Zambezi Delta basin. With the exception of the deeply‐buried centre of the Zambezi Delta depression where potential Jurassic and Lower Cretaceous source rocks were found to be overmature for both oil and gas, modelling showed that potential source rocks in the remaining parts of the study area are mature for hydrocarbon generation. In both the Zambezi Delta depression and Angoche basin, indications for natural gas may be explained by early maturation of oil‐prone source rocks and secondary oil cracking, which likely began in the Early Cretaceous. In distal parts of the Angoche basin, however, the proposed source rocks remain in the oil window.     

澳大利亚西北大陆架与尼日尔三角洲、坎波斯盆地油气地质条件的对比研究

坎波斯盆地、尼日尔三角洲和澳大利亚西北大陆架这3个典型的被动大陆边缘盆地既有相似性,也有不同点,其不同之处表现在:①坎波斯盆地和尼日尔三角洲均只有一期裂谷,西北大陆架各盆地均有多期裂谷,这种多期裂谷使得西北大陆架的油气主要富集在裂谷层系中,而前两者主要分布在漂移层序;②由于烃源岩生烃性质不同,导致不同盆地油气分布特征有差异,前两者油多气少,而西北大陆架富气贫油;③三者油气分布主控因素不同,坎波斯盆地油气藏分布主要与浊积岩和盐岩运动有关,尼日尔三角洲油气藏分布与同生断层有关,西北大陆架油气分布则主要受构造所控制。     

SEQUENCE STRATIGRAPHY AND RESERVOIR CHARACTERISTICS OF THE TURONIAN-CONIACIAN KHASIB FORMATION IN CENTRAL IRAQ

Bioturbated chalky limestones of the Khasib Formation (Upper Turonian – Lower Coniacian) form potential reservoir rocks at oilfields and structures in central Iraq. Core and cuttings samples and wire-line logs from wells in the East Baghdad, Balad, Samarra and Tikrit fields (wells EB-77, EB-57, Ba-1, Ba-2, Sr-1, Sr-2, and Ti-1) were used to investigate microfacies types and porosity evolution. Facies modelling was applied to predict the relationship between facies distribution and reservoir characteristics to construct a predictive geologic model which will assist future exploration in central Iraq. Microfacies analysis and electrofacies identification and correlations indicate that the limestones of the Khasib Formation were deposited in a ramp setting. The ramp developed over the distal margin of the Upper Cretaceous proforeland basin, adjacent to the evolved forebulge. Inner ramp facies are characterized by carbonate bank bioclastic packstones intercalated with lagoonal green shales. Middle ramp facies dominate the Khasib Formation and consist of bioturbated, chalky, dolomitic and bioclastic limestones. Bioclasts include benthic and planktonic foraminifera. Intense Thalassinoides and less common Palaeophycus bioturbation has enhanced the porosity of this facies. Outer ramp deposits consist of alternating mid-ramp bioturbated bioclastic chalky limestones and argillaceous and marly limestones. The latter contain basinal bioclasts including planktonic foraminifera, oligosteginids, dwarf rotaliids, and sponge spicules. Sequence stratigraphic analyses of the Khasib Formation indicate that it represents a third-order depositional cycle. At the base is a type 1 sequence boundary which separates it from the underlying LST deposits of the Kifl Formation. Shaly and argillaceous limestones in the lower part of the Khasib Formation represent the early TST. These are overlain by a thick, deepening-upwards succession of outer ramp facies. The maximum flooding surface is represented by a thin and extensive horizon of Oligosteginal limestones with Palaeophycus bioturbation. HST deposits are represented by aggradational build-ups of bioturbated chalky dolomitic limestones, followed by progradational late HST shales and limestones. The boundary with the overlying Tanuma Formation is a type 2 sequence boundary. Bioclastic packstones and intensively bioturbated (Thalassinoides) bioclastic limestones of the mid-outer ramp are the primary source of fabric-selective porosity which is greatly enhanced by diagenetic overprints. These two units constitute the prime target for future exploration in central Iraq.     

高邮凹陷北斜坡戴南组原油地球化学特征

高邮凹陷北斜坡戴南组油气来源复杂,通过对研究区戴南组已发现油藏原油系统采样,利用色谱—质谱分析技术,分析了原油的生物标志化合物特征,明确了油气来源。研究表明,依据饱和烃色谱及萜、甾烷指纹特征,戴南组原油在Pr/Ph值、规则甾烷、β—胡萝卜烷、伽马蜡烷含量等方面有较明显差别,反映了各类原油来自不同油源,可以划分为3类。Ⅰ类原油来自阜四段和阜二段混源油,母源以高等植物贡献为主,形成于半咸化环境,热演化程度较高;Ⅱ类原油主要来自阜四段成熟油,母源除了有高等植物的输入也有菌藻类等低等水生生物输入;Ⅲ类原油来自阜二段成熟油,母源以高等植物贡献为主,形成于较强的还原咸化环境。     

PETROPHYSICAL AND SEDIMENTOLOGICAL CHARACTERIZATION OF THE APTIAN SHU'AIBA (LOWER QAMCHUQA) FORMATION RESERVOIR AT THE KHABBAZ OILFIELD,NORTHERN IRAQ

The Aptian Shu'aiba Formation is a shallow‐marine carbonate which occurs in the subsurface of central and southern Iraq and in other parts of the Arabian Plate including Oman, the UAE and Saudi Arabia. An equivalent unit is exposed at outcrop in northern Iraq where it is known as the lower part of the Qamchuqa Formation. For this study, core, cuttings and well log data from six wells in the Khabbaz oilfield (20 km SW of Kirkuk) were used to investigate the reservoir properties of the Shu'aiba Formation. The formation is 180–195 m thick at Khabbaz field and the reservoir section can be divided into three lithological units: an upper unit (A, 8–15 m thick) consisting of partly dolomitized marly limestones; a middle unit (B, 52–56 m thick) which is composed of vuggy dolomitic limestone and dolostone; and a lower unit (C, >110 m thick) which consists of shale‐rich and dolomitic limestones. Limestone microfacies include shelfal bioclastic wackestones, Orbitolina bioclastic packstones, Orbitolina grainstones, and pelagic bioclastic wackestones. Dolomite fabrics show little variation and are dominated by coarse crystalline planar‐e types. Most matrix porosity is associated with intercrystalline pores in medium‐crystalline (100–50 µm) planar‐e dolostone. Fracturing of variable intensity has resulted in a flow type which is dominated by fracture flow superimposed on matrix flow.     

开鲁盆地陆西凹陷九佛堂组油气成藏特征及分布

开鲁盆地陆西凹陷属中、新生代断陷盆地,其中九佛堂组发育烃源岩,有机质丰度高,干酪根类型以Ⅱ—Ⅰ型为主,九佛堂组下段烃源岩质量优于上段,均已进入低成熟—成熟阶段。生、排烃主要发生在燕山期—晚白垩世早期,五十家子庙洼陷是最重要的生烃洼陷,小井子洼陷次之。阜新期为主要的油气聚集期。受断裂活动和分布控制的三角洲、近岸水下扇等多种类型的砂体原生孔隙发育,埋深1600m以上的砂体具高—中孔隙度和低—超低渗透率储层物性。沙海组和阜新组的泥岩层是九佛堂组油气藏的区域盖层,九佛堂组的泥岩层可作局部盖层。马家铺高垒带、包日温都断裂带和马北斜坡带与生油洼陷相间,具有良好的生、储配置关系,是油气运移和聚集的指向场所。油气通过断层与砂体共同构成的输导体系运移、聚集至有利的岩性—构造圈闭和岩性圈闭中成藏,预测马家铺高垒带北部和包日温都断裂带中段为最有利的油气勘探区域。     

松辽盆地北部储层压力场特征与油,气,水的关系

本对松辽盆地北部测试地层地系统的鉴别和划分，然后标准类型的测压资料详细研究了压力场特征与油，气，水的关系。     

松辽盆地乾安—长岭凹陷大中型岩性—构造复合型油气田形成特征

松辽盆地南部乾安 长岭凹陷下白垩统发育了多套优质烃源岩和三角洲前缘相砂岩储集层,形成了上、中、下3套成藏组合。在凹陷东部的华字井阶地,具备形成大中型构造—岩性复合型圈闭的各种有利条件:多期三角洲前缘相区纵横交错、相互叠加,经常出现岩性横向相变和上倾尖灭;以乾南潜伏古隆起带古地形为背景形成的继承性南北沉积微相分异;后期构造运动造成盆地东部抬升,使得东部砂体整体上倾尖灭;后期构造运动形成一系列小断裂,对砂体上倾方向产生遮挡;大型斜向水流与区域构造格局的有机配置;成岩作用造成储层致密化。岩性—构造复合圈闭形成于嫩江期及明水期,与大规模油气运移期配置良好,为形成华字井阶地一批大中型构造—岩性复合型油气田创造了条件。      

羌塘盆地羌资2井布曲组碳酸盐岩生物标志物特征及意义

首次报道了藏北羌塘盆地羌资2井中侏罗统布曲组海相碳酸盐岩生物标志化合物特征,该层位含有丰富的正烷烃、类异戊二烯烷烃和萜甾类化合物。正烷烃形态为单峰和双峰并存、以单峰形态占优势,主碳峰以nC₁₇,nC₂₀为主,次为nC₁₈,nC₁₅,nC₁₆,轻烃组分占有绝对优势;OEP值介于0.37~1.14之间,平均值为0.89,无明显的奇偶优势分布;Pr/Ph值介于0.56~1.03之间,平均值为0.75,具有明显的植烷优势。萜烷相对丰度为五环三萜烷>三环萜烷>四环萜烷,伽马蜡烷普遍存在,但相对含量较低;甾烷主要为规则甾烷,少量孕甾烷,规则甾烷∑(C₂₇+C₂₈)>∑C₂₉,∑C₂₇/∑C₂₉介于0.67~1.22之间,显示弱的C₂₇甾烷优势或弱的C₂₉甾烷优势。有机质母质主要来源于藻类等低等水生生物,不能确定是否有陆生高等植物输入。成熟度参数和镜质体反射率均显示碳酸盐岩处于成熟阶段。碳酸盐岩沉积环境总体为缺氧还原—弱还原的海相环境,海水盐度基本正常。     

STRATIGRAPHIC CORRELATION AND SOURCE ROCK CHARACTERISTICS OF THE BALUTI FORMATION FROM SELECTED WELLS IN THE ZAGROS FOLD BELT,KURDISTAN REGION,NORTHERN IRAQ

The Upper Triassic Baluti Formation has been identified and mapped based on its log response in selected wells from the Zagros foldbelt in the Kurdistan Region of northern Iraq. A preliminary evaluation of the formation's source rock potential was made by Rock-Eval screening analysis in four wells along a NW-SE profile (Atrush-1, Shaikan-5B, Taq Taq-22 and Miran-2) with maturity determined from reflectance measurements in samples from well Taq Taq-22. The Baluti Formation consists of thinly interbedded shales, carbonates and anhydrite ranging in thickness from 48 m in well Atrush-1 to 118 m in well Miran-2. The Rock-Eval screening was conducted primarily on bulk cuttings samples plus selected picked cuttings. The TOC content is low to moderate (0.23 to 1.14 wt%). However, the shale content in many of the analysed bulk samples was relatively low, making assessment of the source potential problematic. The highest TOCs are recorded from the thickest analysed sections from wells Miran-2 and Taq Taq-22, where high-gamma bituminous shales are present. Rock-Eval T_max values ranging from 295 to 438°C are not consistent with estimates of pre-Zagros burial to depths of between 4600 m (Atrush-1) and 6900 m (Miran-2). The relatively low T_max values suggest that the S2 response does not reflect kerogen pyrolysis in these samples and may be due to the presence of solid bitumen, which is observed in the Baluti Formation in at least three of the study wells (Taq Taq-22, Miran-2 and Shaikan-5B). Little pyrolysable organic matter remains in the formation due to the interpreted deep pre-Zagros burial and the consequent high maturity in Taq Taq-22 (VR = 1.51%R_o) and Miran-2 (estimated VR >2%R_o), and the poor source character in Atrush-1 and Shaikan-5B. Organic petrography suggests the presence of vestiges of Types I and II kerogen in Taq Taq-22, with bitumen observed as stains in the matrix of the shales and also in the pores and fractures of interbedded dolostones. However, bitumen reflectance determinations for Taq Taq-22 indicate an equivalent vitrinite reflectance maturity of no more than 0.93%R_o, which is significantly less than that of the indigenous vitrinite, implying the solid bitumen in this well is derived primarily from migrated hydrocarbons. Further detailed analysis is required, but the results suggest that the Baluti Formation may have sourced hydrocarbons in its depocentre which is identified in this study as covering a NW-SE trending area between Bekhme and Sangaw.     

塔东古城地区鹰山组白云岩暴露标志识别及其油气地质意义

塔东古城地区鹰山组内部是否存在短期暴露,对明确储层发育主控因素及勘探方向至关重要。通过三维地震、岩心、薄片、测井、录井以及相关地化实验数据等资料分析,识别出钻井的放空及漏失段、地震剖面上具削截反射特征、岩心存在溶蚀缝洞和渗流粉砂充填物、海退现象等4种暴露标志,这些暴露标志有助于层序界面识别和寻找储层发育带。研究认为:鹰山组内部存在一个海平面短暂下降期,鹰山组可划分出4个四级层序,多期次海平面升降旋回控制了"暴露滩体"的垂向格架,各层序高位域碳酸盐岩台地滩暴露地表并遭受大气淡水淋滤和溶蚀,形成优质储层。     

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.