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.     

HYDROCARBON POTENTIAL OF UPPER CRETACEOUS MARINE SOURCE ROCKS IN THE TERMIT BASIN,NIGER

Upper Cretaceous mudstones are the most important source rocks in the Termit Basin, SE Niger. For this study, 184 mudstone samples from the Santonian–Campanian Yogou Formation and the underlying Cenomanian–Coniacian Donga Formation from eight wells were analyzed on the basis of palaeontological, petrographical and geochemical data, the latter including the results of Rock‐Eval, biomarker and stable isotope analyses. Samples from the upper member of the Yogou Formation contain marine algae and ostracods together with freshwater algae (Pediastrum) and arenaceous foraminifera, indicating a shallow‐marine to paralic depositional environment with fresh‐ to brackish waters. Terrestrial pollen and spores are common and of high diversity, suggesting proximity to land. Samples from the lower member contain marine algae and ostracods and arenaceous foraminifera but without freshwater algae, indicating shallow‐marine and brackish‐water settings with less freshwater influence. The wide range of gammacerane index values, gammacerane/C₃₀ hopane (0.07–0.5) and Pr/Ph ratios (0.63–4.68) in samples from the upper member of the Yogou Formation suggest a low to moderately saline environment with oxic to anoxic conditions. In samples from the lower member, the narrower range of the gammacerane index (0.23～0.35) and Pr/Ph ratios (0.76–1.36) probably indicate a moderately saline environment with suboxic to relatively anoxic conditions. Petrographic analyses of the Yogou Formation samples show that organic matter is dominated by terrestrial higher plant material with vitrinite, inertinite and specific liptinites (sporinite, cutinite and resinite). Extracts are characterized by a dominance of C₂₉ steranes over C₂₇ and C₂₈ homologues. Results of pyrolysis and elemental analyses indicate that the organic matter is composed mainly of Type II kerogen grading to mixed Type II‐III and Type III material with poor to excellent petroleum potential. Mudstones from the upper member of the Yogou Formation have higher petroleum generation potential than those from the lower member. Mudstones in the Donga Formation are dominated by Type III organic matter with poor to fair petroleum generation potential. Geochemical parameters indicate that in terms of thermal maturity the Yogou Formations has reached or surpassed the early phase of oil generation. Samples have T_max values and 20S/(20S+20R) C₂₉ sterane ratios greater than 435°C and 0.35, respectively. 22S/(22S+22R) ratios of C₃₁ homohopanes range from 0.50 to 0.54. The results of this study will help to provide a better understanding of the hydrocarbon potential of Upper Cretaceous marine source rocks in the Termit Basin and also in coeval intracontinental rift basins such as the Tenere Basin (Niger), Bornu Basin (Nigeria) and Benue Trough (Nigeria).     

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.     

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.     

SOURCE ROCK POTENTIAL OF THE UPPER JURASSIC – LOWER CRETACEOUS SUCCESSION IN THE SOUTHERN MESOPOTAMIAN BASIN,SOUTHERN IRAQ

This paper reports on the hydrocarbon potential of subsurface samples from the Upper Jurassic Lower Cretaceous succession at the Rumaila (North and South), Zubair, Subba and West Qurna oilfields in southern Iraq. A total of 37 fine‐grained core samples of the Sulaiy, Yamama, Ratawi and Zubair Formations from ten wells were analyzed. Contents of organic carbon and sulphur were measured; other analyses included Rock‐Eval pyrolysis, optical microscopy in incident light, solvent extraction and gas chromatography of non‐aromatic hydrocarbons. The results indicated that the samples from the Cretaceous succession (Yamama, Zubair and Ratawi Formations) are at moderate levels of thermal maturity, whereas samples from the Upper Jurassic – Lower Cretaceous Sulaiy Formation are at a stage of thermal maturity beyond peak oil generation. According to the results of this study, the Sulaiy Formation is an excellent highly‐mature source rock and it is probably responsible for the generation of large quantities of oil in the study area. The samples differ with respect to their organic fades and biomarker distribution, indicating that palaeo depositional conditions varied significantly.     

HIGH‐RESOLUTION STRATIGRAPHY,PALYNOFACIES AND SOURCE ROCK POTENTIAL OF THE ÁGUA DE MADEIROS FORMATION (LOWER JURASSIC), LUSITANIAN BASIN,PORTUGAL

In the Lusitanian Basin (central‐western Portugal), the Lower Jurassic carbonate‐dominated succession is thought to have significant source rock potential. One of the most important units is the Água de Madeiros Formation (Upper Sinemurian – lowermost Pliensbachian) which is composed of alternating organic‐rich marls and limestones including black shale horizons. This paper is based on a study of this formation at its type locality at S. Pedro de Moel in western Portugal. Data includes Total Organic Carbon (TOC) measurements, palynofacies analyses and results of Rock‐Eval pyrolysis presented within a high‐resolution lithostratigraphic framework. TOC contents were measured in some 200 samples from the Água de Madeiros Formation covering a stratigraphic interval of 58 m, and vary widely up to a maximum of about 22 wt %. Kerogen assemblages are dominated by marine amorphous organic matter with varying contributions by phytoclasts and palynomorphs. A majority of the 85 samples analyzed by Rock‐Eval pyrolysis have S₂ values above 10 mg HC/g rock, reaching a maximum of 78 mg HC/g rock. These high S₂ values are correlative with maximum values of the Hydrogen Index which averages 355 mg HC/g TOC (maximum of 637 mg HC/g TOC). However in spite of these indicators of source‐rock potential, the Água de Madeiros Formation in the study area is thermally immature or very early mature, as indicated by T_max values below 437 °C and average vitrinite reflectance values of 0.43 % R_o.     

BIOMARKER GEOCHEMISTRY OF CRUDE OILS AND NEOGENE BITUMINOUS SHALES IN THE YENIKÖY AREA,EREĞLI‐ULUKIȘLA BASIN,CENTRAL ANATOLIA,TURKEY

In the Ere?li‐Uluk??la Basin, southern Turkey, crude oil shows have been observed in the subsurface in the shale‐dominated non‐marine Upper Miocene – Pliocene succession. Based on analyses of samples from four boreholes, the shales’ organic matter content, thermal maturity and depositional characteristics are discussed in this study. Geochemical correlations are established between shale extracts and a crude oil sampled from the shale succession. The shales have moderate to high hydrogen index (HI) and very low oxygen index (OI) values. Pyrolysis data show that the shales contain both Types I and II kerogen, and n‐alkane and biomarker distributions indicate that organic matter is dominated by algal material. Very high C₂₆/C₂₅ and C₂₄/C₂₃, and low C₂₂/C₂₁ tricyclic terpane ratios and C₃₁ R/C₃₀ hopane, C₂₉/(C₂₈+C₂₉) MA and DBT/P ratios in shale extracts indicate that deposition occurred in a lacustrine setting. High gammacerane and C₃₅ homohopane concentrations and low diasterane/sterane ratios with a very low Pr/Ph ratio suggest that both the shales and the source rocks for the oil were deposited in a highly anoxic environment in which the water column may have been thermally stratified. Although the shales analysed have very low T_max values, the production index is quite high which suggests that the shales are early‐mature to mature. Biomarker ratios including C₃₂ 22S/(22R+22S) homohopanes, C₂₉ 20S/(20R+20S) and ββ(ββ+αα) steranes, moretane/hopane, TA(I)/TA(I+II) and MPI‐3 all suggest that the shales are within the oil window. Heavy components of free hydrocarbons (S₁) within the shales may have been recorded as part of the Rock‐Eval S₂ peak resulting in the low T_max values. The oil and shale extracts analysed are similar according to their sterane and triterpane distributions, suggesting that the oil was generated by the shales. However burial depths of the Upper Miocene – Pliocene shale succession are not sufficient for thermal maturation to have occurred. It is inferred that intense volcanism during the Pliocene – Pleistocene may have played an important role in local maturation of the shale succession.