TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES,DANISH CENTRAL GRABEN,NORTH SEA

The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.     

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

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

OIL FAMILY TYPING,BIODEGRADATION AND SOURCE ROCK AFFINITY OF LIQUID PETROLEUM IN THE DANISH NORTH SEA

Variations in liquid petroleum compositions in the Danish Central Graben and Siri Fairway, North Sea, demonstrate the presence of several active source rock facies. To address this issue in detail, a total of 213 samples of liquid petroleum from the Danish Central Graben and the Siri Fairway were typed to eight main oil families and three sub‐families based on characteristic geochemical properties and principal component analysis (PCA). Comparison with source rock extract data made it possible to suggest correlative source rocks for each oil family together with the source rock depositional environments. The main oil families are: 1(B), 2(B), 3a(B), 3b(B), 4(B‐D/E), 5(D/E‐B), 6(D/E‐F) and 7(A), where the capital letters in brackets refer to the organofacies types of Pepper and Corvi (1995), thus directly linking the oil family type to the source rock facies. Oil families 1(B), 2(B), 3a(B) and 3b(B) were charged from marine shales (principally the Upper Jurassic Farsund Formation); oil families 4(B‐D/E) and 5(D/E‐B) are mixed petroleums with both terrigenous and marine components; oil family 6(D/E‐F) was charged from Middle Jurassic coaly units; whereas oil family 7(A) was charged from a carbonate source (Zechstein dolomites). Family 7(A) has only been documented in the form of oil stains. The most widespread oil family is 3a(B), sourced from Upper Jurassic marine shales. Charging from different organofacies is indicated by oil family 3b(B), which was derived from parts of the same shale succession which were more terrigenous‐influenced and possibly slightly more oxic; and families 2(B) and 1(B), which were sourced from more organic‐rich, anoxic parts of the shales. Mildly biodegraded oils (Level 1 to 2) appear mainly to occur in the central to southern parts of the Danish Central Graben.     

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.     

APPLICATION OF MUD GAS DATA AND LEAKAGE PHENOMENA TO EVALUATE SEAL INTEGRITY OF POTENTIAL CO2 STORAGE SITES: A STUDY OF CHALK STRUCTURES IN THE DANISH CENTRAL GRABEN,NORTH SEA

Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO₂ storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C₃–C₅, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C₁ (methane) and partly C₂ (ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal >30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane-derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe-out zones (gas chimneys), bright zones (gas-charged sediments or MDACs), and depressions (pockmarks). In general, potential CO₂ storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO₂ storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (palaeo-) leakage phenomena and provide support for seal integrity evaluation at local to regional scales.     

南海东北部中晚中生代构造、古地理背景及油气远景分析

对前人研究成果的综合分析表明 ,自晚三叠世以来 ,影响南海东北部构造及古地理、古气候的因素主要是太平洋而并非特提斯。本区晚三叠世—早侏罗世古地理和古气候条件有利于煤系烃源岩的形成 ;中侏罗世—白垩纪古气候条件对生烃相对不利 ;晚中生代弧前盆地构造背景不利于形成特提斯域所拥有的优质碳酸盐岩 蒸发岩储盖组合。勘探实践证明 ,南海东北部的中生界具有一定的油气远景 ,但油气勘探不应简单套用特提斯模式     

苏北盆地与南黄海盆地中——新生界成烃对比浅析

苏北与南黄海盆地是统一的中—新生代盆地。苏北盆地勘探成果丰富,地化甄别7套暗色泥岩仅4套对成藏有贡献,3套属拗陷广湖灰泥岩,分布广、质量稳定,岩电特征突出;1套属断陷湖的纯泥岩。重新厘定南黄海盆地烃源岩,确认南坳有5套烃源岩,套数比苏北多、厚度略大,北坳仅有1套;各套形成环境、岩电特征与苏北相似,但品质和稳定性略差。两盆地烃源岩都处低熟—成熟阶段,南黄海总体低于苏北,成熟可排烃源岩范围较苏北小。烃源岩质量、成熟度和排烃畅通度决定苏北各凹陷油气资源丰度,成熟度高、排烃畅通资源丰度高,相反则低;断陷沉积埋藏越发展,烃源岩越成熟,三垛期末为烃源岩成熟定型期。综合看,南黄海资源潜力不如苏北,南坳优于北坳。     

OIL‐IMPREGNATED FLINT IN DANIAN CHALK IN THE TYRA FIELD,NORTH SEA CENTRAL GRABEN

A new model has recently been proposed for the formation of flint in Danian North Sea chalk, according to which nano‐quartz spheres crystallized in the marine water column and were then deposited and compacted, ultimately forming flint. This depositional origin implies that apparently massive flint blocks may have a porous structure. Internal flint porosity is supported by observations on an oil‐impregnated flint nodule recovered from the gas and oil zone in the Tyra field, well E‐5. Samples from the flint nodule have been investigated – the mineralogy by X‐ray diffraction and thermal analysis, and the structure by Atomic Force Microscopy (AFM) and helium porosimetry. In addition, organic‐geochemical analyses of the hydrocarbons in the flint nodule were carried out. The structure of the flint, which is composed of nano‐size spheres, indicates that significant porosity related to micro‐sized pore spaces may be present. Measurements on the flint nodule using standard He‐porosimetry demonstrate a porosity of 16.5% which is of the same order of magnitude as that measured in the overlying chalk. The oil extracted from the nodule has a composition similar to that present in other reservoirs nearby. The presence of oil in the flint nodule examined suggests that the porous proto‐flint formed part of the reservoir section as both chalk and flint were filled simultaneously with hydrocarbons.     

苏北-南黄海盆地构造演化

苏北及南黄海盆地是由多期、多类盆地叠加的复合残留盆地,地质概况基本相似,成因演化近同,自元古界下扬子板块形成后,主要经历了古-中生代地台、中生代前陆盆地、走滑拉分盆地时期以及新生代断陷、坳陷盆地时期.在古生代-中生代发展过程中是一个整体,晚白垩世盆地演化出现分化,发育伸展盆地群,形成一系列叠置在中、古生代盆地之上的箕状断陷,箕状断陷的发育及分布明显受中-古生界内部先存逆冲断裂的控制.     

多介质立体取样及在北黄海油气化探中的应用

由于不同环境条件下,不同化探测试指标受到不同的因素干扰,所以不同介质样品的应用条件存在一定的差异。针对不同介质样品特点,分别采集海底沉积物、底部海水和低空大气3种介质样品,并采用在海底沉积物柱状样不同深度部位取样的立体取样方法,通过多指标综合分析,对不同介质和深度样品的多项化探指标互相进行了验证和补充,可以抑制干扰因素的影响,为油气资源远景评价提供依据。运用该方法在北黄海盆地油气勘查中进行初步尝试,并据此划分了三级化探异常区,提出了有利的含油气远景区,均与已知油气区和区域地质分析的结果相符合,取得了很好的效果。