Geochemical Evaluation of the Permian Ecca Shale in Eastern Cape Province,South Africa: Implications for Shale Gas Potential

Shale gas has been the exploration focus for future energy supply in South Africa in recent time. Specifically, the Permian black shales of the Prince Albert, Whitehill, Collingham, Ripon and Fort Brown Formations are considered to be most prospective rocks for shale gas exploration. In this study,outcrop and core samples from the Ecca Group were analyzed to assess their total organic carbon(TOC), organic matter type, thermal maturity and hydrocarbon generation potential. These rocks have TOC ranging from 0.11 to 7.35 wt%. The genetic potential values vary from 0.09 to 0.53 mg HC/g,suggesting poor hydrocarbon generative potential. Most of the samples have Hydrogen Index(HI) values of less than 50 mg HC/g TOC, thus suggesting Type-Ⅳ kerogen. Tmax values range from 318℃ to601℃, perhaps indicating immature to over-maturity of the samples. The vitrinite reflectance values range from 2.22% to 3.93%, indicating over-maturity of samples. Binary plots of HI against Oxygen Index(OI), and HI versus Tmax show that the shales are of Type II and mixed Type Ⅱ-Ⅲ kerogen.Based on the geochemical data, the potential source rocks are inferred as immature to over-matured and having present-day potential to produce gas.     

Source Rock Characterization and Petroleum Systems in North Ghadames Basin,Southern Tunisia

This paper presents geochemical analysis of drilled cutting samples from the OMZ‐2 oil well located in southern Tunisia. A total of 35 drill‐cutting samples were analyzed for Rock‐Eval pyrolysis, total organic carbon (TOC), bitumens extraction and liquid chromatography. Most of the Ordovician, Silurian and Triassic samples contained high TOC contents, ranging from 1.00 to 4.75% with an average value of 2.07%. The amount of hydrocarbon yield (pyrolysable hydrocarbon: S2b) expelled during pyrolysis indicates a good generative potential of the source rocks. The plot of TOC versus S2b, indicates a good to very good generative potential for organic matter in the Ordovician, Silurian and Lower Triassic. However, the Upper Triassic and the Lower Jurassic samples indicate fair to good generative potential. From the Vankrevelen diagram, the organic matter in the Ordovician, Silurian and Lower Triassic samples is mainly of type II kerogen and the organic matter from the Upper Triassic and the Lower Jurassic is dominantly type III kerogen with minor contributions from Type I. The thermal maturity of the organic matter in the analyzed samples is also evaluated based on the T_max of the S2b peak. The Ordovician and Lower Silurian formations are thermally matured. The Upper Silurian and Triassic deposits are early matured to matured. However, Jurassic formations are low in thermal maturity. The total bitumen extracts increase with depth from the interval 1800–3000 m. This enrichment indicates that the trapping in situ in the source rocks and relatively short distance vertical migration can be envisaged in the overlying reservoirs. During the vertical migration from source rocks to the reservoirs, these hydrocarbons are probably affected by natural choromatography and in lower proportion by biodegradation.     

Source potential and palynofacies of Late Jurassic “Lemeš facies”, Croatia

Laminated limestone and calcareous shale outcrop samples from the Late Jurassic “Leme?” facies (Croatia) were investigated to characterize their organic facies and palynofacies and their hydrocarbon generative potential. The results indicate that the organic rich sediments of “Leme?” facies were deposited within a relatively shallow marine environment at low redox potential, characterized as an oxygen depleted depositional setting with stratified bottom waters of the carbonate platform (Adriatic Carbonate Platform). The organic rich samples contain a high portion of lipid rich amorphous kerogen of algal/phytoplankton origin, enriched by bacterial biomass. Most of the analyzed samples have total organic carbon contents (TOC) greater than 3%, Rock-Eval S2 >20 mg HC/g rock, yielding Hydrogen Index (HI) values ranging from 509–602 mg HC/g TOC. According to these results, the analyzed samples have very good to excellent oil generative potential. Relatively high sulfur content suggests that the kerogen is best described as Type II-S. Biomarker maturity parameters, as well as the fluorescence of the isolated kerogen, show that the organic matter is at early to peak oil thermal maturity. The observed level of thermal maturity indicates that these samples were once buried to depths of ～5.5–5.8 km before being uplifted in the late Tertiary. The surface outcrops of the “Leme?” facies suggest that these strata have significant source potential and are the likely source of oil in the Croatian External Dinarides.     

Source rock potential of selected Cretaceous shales,Orange Basin,South Africa

Twenty Cretaceous shale samples from two wells in the Orange Basin of South Africa were evaluated for their source rock potential. They were sampled from within a 1400 m-thick sequence in boreholes drilled through Lower to Upper Cretaceous sediments. The samples exhibit total organic carbon (TOC) content of 1.06–2.17%; Rock-Eval S2 values of 0.08–2.27 mg HC/g; and petroleum source potential (SP), which is the sum of S1 and S2, of 0.10–2.61 mg HC/g, all indicating the presence of poor to fair hydrocarbon generative potential. Hydrogen index (HI) values vary from 7 to 128 mg HC/g organic carbon and oxygen index (OI) ranges from 37 to 195 mg CO₂/g organic carbon, indicating predominantly Type III kerogen with perhaps minor amounts of Type IV kerogen. The maturity of the samples, as indicated by T _max values of 428–446°C, ranges from immature to thermally mature with respect to oil generation. Measured vitrinite reflectance values (%Ro) of representative samples indicate that these samples vary from immature to mature, consistent with the thermal alteration index (TAI) (spore colour) and fluorescence data for these samples. Organic petrographic analysis also shows that amorphous organic matter is dominant in these samples. Framboidal pyrite is abundant and may be indicative of a marine influence during deposition. Although our Rock-Eval pyrolysis data indicate that gas-prone source rocks are prevalent in this part of the Orange Basin, the geochemical characteristics of samples from an Aptian unit at 3318 m in one of the wells suggest that better quality source rocks may exist deeper, in more distal depositional parts of the basin.     

Paleocene-Eocene potential source rocks in the Avengco Basin,Tibet: Organic geochemical characteristics and their implication for the paleoenvironment

The Avengco Basin is located in the western part of the Tibetan Plateau and is similar to the Nima Basin in the central part of the plateau and the Lunpola Basin in the eastern part in terms of sedimentary characteristics and tectonic settings, which are well known to provide a good source rock potential. However, the organic geochemical characteristics of the Paleocene-Eocene potential source rocks in the Avengco Basin have been under debate. Thirty-four marl and mudstone outcrop samples of the Niubao Formation in the Avengco Basin were collected and subjected to the following analyses: total organic carbon (TOC), Rock–Eval pyrolysis, stable carbon isotopes of kerogen, gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS). Here, we present the results indicating the organic matter of the upper Niubao Formation is mainly composed of Type II kerogen with a mixed source, which is dominated by algae. However, the lower Niubao Formation has the less oil-prone Type II–III kerogen, and the sources of the organic matter are mainly terrestrial plants with less plankton. In addition, the samples are thermally immature to marginally mature. The Niubao Formation was deposited in an anoxic–oxic environment which was brackish with an imperceptible stratified water column. The upper Niubao Formation has a medium to good hydrocarbon-generating potential. However, the lower Niubao Formation has a zero to poor hydrocarbon-generating potential.     

封闭体系有机质与有机碳氢氮恢复动力学研究

在封闭体系的条件下,对典型的Ⅰ、Ⅱ、Ⅲ型干酪根在热演化过程中的损失进行生烃动力学研究,获得了Ⅰ、Ⅱ、Ⅲ型干酪根的总量、有机碳、氢以及氮质量损失动力学参数。用Kinetics软件计算了封闭体系干酪根有机碳丰度、氢碳原子比和氮碳原子比的恢复系数。认为在对高成熟—过成熟干酪根进行生烃评价时,Ⅰ、Ⅲ型干酪根残余有机碳丰度需要进行恢复,而Ⅱ型干酪根残余有机碳丰度不需要恢复。三种类型干酪根的氢碳原子比均需要进行恢复。     

Geochemical and petrographic characterization of organic matter in the Upper Jurassic Madbi shale succession (Masila Basin,Yemen): Origin,type and preservation

The Upper Jurassic Madbi Formation, located in the Masila Basin, eastern Yemen, represents the major source rock in this basin. Organic rich shales from two oilfields (Kharir and Wadi Taribah) were analysed to evaluate the type and origin of the organic matter and to determine the factors controlling its deposition. This study is based on geochemical analyses of whole rock (total organic carbon content, Rock-Eval pyrolysis and carbon isotope data) and petrographic analyses on organic matter (kerogen maceral composition and palynofacies) by optical and scanning electron microscopy. Organic petrographic composition of kerogen shows that the Madbi shale is characterized by high amounts of organic matter, consisting predominantly of yellow fluorescing amorphous organic matter and alginite of marine origin. Terrigenous organic materials such as vitrinite, spores and pollen are present in low quantities. The predominance of marine plankton, as indicated by visual kerogen analysis, is consistent with reported carbon isotopic values. It appears that the high amounts of organic matter in the Madbi shale succession might be mainly due to good preservation under suboxic–anoxic conditions. Consequently the Madbi shales possess very good petroleum generative potential, owing to high content of hydrogen rich Type II and I oil prone kerogen.     

Paleoenvironments, organic petrology and Rock-Eval studies on source rock facies of the Lower Maastrichtian Patti Formation, southern Bida Basin, Nigeria

The southern Bida Basin in central Nigeria forms a part of the larger Bida or Middle Niger Basin, which is contiguous with the south east trending (petroliferous) Anambra Basin. These basins were major depocenters for Campanian–Maastrichtian sediments in southern and central Nigeria prior to the build up of the Tertiary Niger delta. The successions in the southern Bida Basin consist of the basal Lokoja Formation, overlain by the Patti Formation and capped by the Agbaja Formation. The Lokoja Formation is a sequence of matrix supported conglomerates and sandstones overlying the Pre-Cambrian to Lower Paleozoic basement. Depositional environments are predominantly within fluvial systems of a continental setting. The Patti Formation consists of dark grey carbonaceous shales; mudstone and siltstones representing flood plains to shallow marine deposits with likely organic rich intervals. The overlying Agbaja Formation is made up of ferruginised oolitic and kaolinitic mudstone of a marginal marine environment. Twenty samples of shales of the Patti Formation were studied by incident light microscopy and geochemical analysis to determine the maceral components, geochemical type and potential yield of the pyrolysate. Maceral analysis indicate a large abundance of vitrinite (50–85%; mean = 66%); moderate abundance of liptinites (10–33%; mean = 18%) and lesser amounts of inertinite (9–40%; mean = 16%). Total organic carbon (TOC) values vary from 0.17 to 3.8 wt.% (mean = 2.1 wt.%) with most samples having greater than 2 wt.% TOC. Three of the samples yield greater than 2 kg_(HC)/ton of rock suggesting a fair source rock potential. Most of the samples are thermally immature to marginally mature with vitrinite reflectance ranging from 0.4 to 0.6% R_om and T_max values of 407–426 °C. Given the prevalence of the humic Type III kerogen, maturity and hydrocarbon potential yields, we conclude that the Patti Formation source rock facies have moderate to fair potential for gaseous hydrocarbons which have not yet been generated at the present day outcrop levels but could be important gas source where buried down-dip.     

碳酸盐岩有机质丰度测试新方法

常规有机碳测试中仅对残余固相进行测试而忽略了酸解液,而前人研究证实酸解液中含有一定量的有机质。为了准确定量碳酸盐岩样品的总有机碳(TOC),提出蒙脱石增稠元素分析的新方法。本次研究以配比标样(CaCO₃+SiO₂+有机质标样)作为研究对象,对配比标样进行传统有机碳测试以及酸解后利用蒙脱石增稠进行元素分析的新方法测试。结果显示加入有机质标样为小分子有机酸(盐)的配比标样的传统有机碳测试的相对误差为98.5%~99.6%,加入大分子有机质的配比标样传统有机碳测试的相对误差较小,为11.9%~48.1%。而酸解后蒙脱石增稠进行元素分析测试的方法中,总有机碳(TOC)的相对误差为0.76%~19.46%。不同有机碳浓度的配比标样的元素分析法测试结果的相对误差随着有机碳浓度的增大而减小。新有机碳测试方法中,由于除去无机碳后将残渣与酸解液混合均匀并增稠,避免了有机碳的流失,更能客观反映样品总有机碳(TOC)。     

鄂尔多斯盆地下奥陶统碳酸盐岩有机相类型及生烃潜力

对鄂尔多斯盆地下奥陶统马家沟组碳酸盐岩的各种沉积环境的有机相特征进行了研究,结果表明平均有机碳丰度最高的是陆缘斜坡相碳酸盐岩(0.26%),其次是膏盐湖(0.22%)、膏云坪(0.21%),而开阔海、云坪和滩等环境的碳酸盐岩有机碳平均含量较低(<0.20%);碳酸盐岩干酪根样品多数为富氧、贫氢,显示其有机质类型较差;岩石地球化学特征和生物化石特征反映出陆缘斜坡处于相对还原的环境,而其他沉积环境则为氧化环境。鄂尔多斯盆地下奥陶统的大部分碳酸盐岩处于生烃潜力较差的C～D相。从有机质数量、有机相类型来判断,鄂尔多斯盆地下奥陶统碳酸盐岩不是好烃源岩,难以形成具有一定规模的气田。     

Characterization of organic-rich material in an evaporitic environment: the Lower Oligocene of the Mulhouse basin (Alsace,France)

Evaporitic sediments from the Max borehole (Mulhouse Potash Basin, southern Rhine Graben) were studied over an interval of about 40 m in the vicinity of sylvite beds. Total organic carbon (TOC) analyses of 450 samples showed that marly layers interbedded within the evaporites have TOC values that fluctuate in a rhythmic manner; the highest values are found near the top of the clay—anhydrite layers and the lowest values are recorded near the top of the halite-rich beds. Geochemical (elemental analysis of kerogen, gas chromatography of bitumen) and palynological studies of 26 samples showed that the organic matter is mainly of algal origin (A and B groups). A third category of organic material (C group) may have been derived from a mixture of continental supply and in situ bacterial productivity.     

Late Albian–Middle Cenomanian palynofacies and palynostratigraphy, Abu Gharadig-5 well, Western Desert, Egypt

Quantitative analyses of palynomorph assemblages, particulate organic matter (kerogen), and total organic carbon (TOC) have been made on samples of the Albian–Cenomanian Kharita and Bahariya formations encountered in the Abu Gharadig-5 well, Western Desert, Egypt. Two assemblage palynozones are defined: Assemblage Zone A (Kharita Formation) of late Albian–early Cenomanian age and Assemblage Zone B (Bahariya Formation) of early–middle Cenomanian age. Palynofacies of the Kharita Formation suggest that sedimentation of these strata took place in a warm, shallow, nearshore-marine environment. The deposition of the lower Bahariya Formation took place initially in similar conditions but subsequently further offshore in somewhat deeper water of the inner shelf. The relatively high percentage of Ephedripites, Afropollis and elaterate pollen in both formations indicates an arid climate. The Kharita Formation yields kerogen types III and IV whereas the assemblages recovered from the Bahariya Formation contain types II and III. The TOC is generally between 0.42 and 0.65% in the Kharita Formation, while it ranges between 0.42 and 0.80% in samples of the Bahariya Formation. The spores and pollen grains are pale in colour; hence little source potential for hydrocarbons is indicated.     

Palynomorph stratigraphy,palynofacies and organic geochemistry assessments for hydrocarbon generation of Ratawi Formation,Iraq

Seventy-two core and cutting samples of the Ratawi Formation from selected wells of central and southern Iraq in Mesopotamian Foredeep Basin are analysed for their sedimentary organic matters. Dinoflagellates, spores and pollen are extracted by palynological techniques from these rocks. Accordingly, Hauterivian and late Valanginian ages are suggested for their span of depositional time. These palynomorphs with other organic matter constituents, such as foraminifer’s linings, bacteria and fungi, are used to delineate three palynofacies types that explain organic matter accumulation sites and their ability to generate hydrocarbons. Palaeoenvironments of these sites were mainly suboxic to anoxic with deposition of inshore and neritic marine environments especially for palynofacies type 2. Total organic matters of up to 1.75 total organic carbon (TOC) wt.% and early mature stage of up to 3.7 TAI based on the brown colour of the spore species Cyathidites australis and Gleichenidites senonicus with mottled interconnected amorphous organic matter are used for hydrocarbon generation assessment from this formation. On the other hand, these rock samples are processed with Rock-Eval pyrolysis. Outcomes and data calculations of these analyses are plotted on diagrams of kerogen types and hydrocarbon potential. Theses organic matter have reached the mature stage of up to T _max?=?438 °C, hydrogen index of up to 600 mg hydrocarbons for each gram of TOC wt.% and mainly low TOC (0.50–1.55). Accordingly, this formation could generate fair quantities of hydrocarbons in Baghdad oil field and Basrah oil fields. Organic matters of this formation in the fields of Euphrates subzone extends from Hilla to Nasiriyah cities have not reached mature stage and hence not generated hydrocarbons from the Ratawi Formation. Software 1D PetroMod basin modelling of the Ratawi Formation has confirmed this approach of hydrocarbon generation with 100 % transformations of the intended organic matters to generate hydrocarbons to oil are performed in especially oil fields of East Baghdad, West Qurna and Majnoon while oil fields Ratawi and Subba had performed 80–95 % transformation to oil and hence end oil generation had charged partly the Tertiary traps that formed during the Alpine Orogeny. Oil fields of Nasiriyah and Kifle had performed least transformation ratio of about 10–20 % transformation to oil, and hence, most of the present oil in this field is migrated from eastern side of the Mesopotamian Foredeep Basin that hold higher maturation level.     

Hydrocarbons generation potential of the Jurassic–Lower Cretaceous Formation, Ajeel field, Iraq

Organic geochemical analysis and palynological studies of the organic matters of subsurface Jurassic and Lower Cretaceous Formations for two wells in Ajeel oil field, north Iraq showed evidences for hydrocarbon generation potential especially for the most prolific source rocks Chia Gara and Sargelu Formations. These analyses include age assessment of Upper Jurassic (Tithonian) to Lower Cretaceous (Berriasian) age and Middle Jurassic (Bathonian–Tithonian) age for Chia Gara and Sargelu Formations, respectively, based on assemblages of mainly dinoflagellate cyst constituents. Rock-Eval pyrolysis have indicated high total organic carbon (TOC) content of up to 18.5 wt%, kerogen type II with hydrogen index of up to 415 mg HC/g TOC, petroleum potential of 0.70–55.56 kg hydrocarbon from each ton of rocks and mature organic matter of maximum temperature reached (T_max) range between 430 and 440 °C for Chia Gara Formation, while Sargelu Formation are of TOC up to 16 wt% TOC, Kerogen type II with hydrogen index of 386 mg HC/g TOC, petroleum potential of 1.0–50.90 kg hydrocarbon from each ton of rocks, and mature organic matter of T_max range between 430 and 450 °C. Qualitative studies are done in this study by textural microscopy used in assessing amorphous organic matter for palynofacies type belonging to kerogen type A which contain brazinophyte algae, Tasmanites, and foraminifera test linings, as well as the dinoflagellate cysts and spores, deposited in dysoxic–anoxic environment for Chia Gara Formation and similar organic constituents deposited in distal suboxic–anoxic environment for Sargelu Formation. The palynomorphs are of dark orange and light brown, on the spore species Cyathidites australis, that indicate mature organic matters with thermal alteration index of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation by Staplin's scale. These characters have rated the succession as a source rock for very high efficiency for generation and expulsion of oil with ordinate gas that charged mainly oil fields of Baghdad, Dyala (B?aquba), and Salahuddin (Tikrit) Governorates. Oil charge the Cretaceous-Tertiary total petroleum system (TPS) are mainly from Chia Gara Formation, because most oil from Sargelu Formation was prevented passing to this TPS by the regional seal Gotnia Formation. This case study of mainly Chia Gara oil source is confirmed by gas chromatography–mass spectrometry analysis for oil from reservoirs lying stratigraphically above the Chia Gara Formation in Ajeel and Hamrine oil fields, while oil toward the north with no Gotnia seal could be of mainly Sargelu Formation source.     

鄂尔多斯盆地南部长7页岩沉积特征和有机质富集因素研究

对鄂尔多斯盆地南部瑶科1（YK1）井延长组长7段页岩45件样品进行了总有机碳、Rock-Eval热解分析,并且对其中的15个样品进行了有机碳同位素组成分析、氯仿沥青“A”含量和微量元素分析。结果显示,长7段有机质丰度指标（TOC、氯仿沥青“A”、生烃潜量）之间具有良好的相关性,长73有机质丰度高于长71,长72有机质丰度最低;有机碳同位素指示长73层有机质类型好,以Ⅰ型为主,长72和长71层有机质以Ⅰ和Ⅱ型为主;氧化还原指标U/Th、δU和V/(V+Ni)值指示长7沉积时期水体整体为还原-强还原环境,其中,相比长72和长71的沉积环境,长 73的沉积环境还原性更强,可能达到厌氧、硫化细菌发育的程度。页岩中高P元素含量,指示YK1井长7段页岩沉积时期具有高古生产力特征。有机碳含量（TOC）与氧化还原指标和P元素呈良好的正相关关系,表明有机质含量的变化同时受控于古生产力高低和氧化还原的保存条件。因此,长7段页岩有机质富集模式可能属于“生产力模式”,即长7页岩有机质的富集是由于较高的初始生产力通过消耗水体中的氧气而形成易于保存有机质的缺氧环境。综合前人的页岩气研究成果,认为富有机质的长73层是鄂尔多斯盆地南部页岩气富集的最有利层段。     

内蒙古西部额济纳旗祥探9井石炭系—二叠系烃源岩地球化学特征

额济纳旗地区祥探9井揭示的石炭系—二叠系为火山岩＋碎屑岩组合,火山岩锆石U-Pb谐和年龄分布在（302.2±7.8）-（319.9±4.5）Ma之间,对应的地层时代相当于晚石炭世,岩性组合特征与大狐狸山剖面干泉组（C2P1g）可以对比,确定为干泉组。该井揭示石炭系—二叠系1027.4m（未穿）,其中4m和4m以上的暗色泥岩（或粉砂质泥岩）20层,累计厚度288.5m,占地层厚度的28.1%。少量钻井岩心样品进行的烃源岩地球化学特征分析表明,有机质丰度中等—好,干酪根类型为Ⅰ—Ⅱ1型,有机质演化进入成熟—高成熟阶段,显示了良好的生烃条件。与邻近的大狐狸山剖面干泉组烃源岩样品分析结果对比,祥探9井取得的样品有机质丰度显著高于地表剖面样品,TOC为地表剖面样品的1.8倍,热解产油潜量（S1＋S2）为地表剖面样品的295.3倍,氯仿沥青＂A＂为地表剖面样品的32.8倍,总烃（HC）为地表剖面样品的42倍。干酪根类型评价指标分析,井下岩心样品H/C-O/C能较好地反映干酪根类型,地表剖面样品受风化作用的影响H元素显著降低,H/C-O/C无法进行干酪根类型评价,说明风化作用对烃源岩丰度和类型评价指标的影响较大。     

The shale gas potential of Tournaisian, Visean, and Namurian black shales in North Germany: baseline parameters in a geological context

Carboniferous black mudrocks with known petroleum potential occur throughout Northern Germany. However, despite numerous boreholes exploring for conventional hydrocarbons, the potential for shale gas resources remains uncertain. Therefore, an integrated investigation was conducted to elucidate the shale gas potential for three different Carboniferous facies incorporating baseline parameters from sedimentological and organic-geochemical analyses. Tournaisian–Namurian fine-grained rocks of the Culm-facies, with Type II + III kerogen were deposited in the basin center. TOC contents of up to 7 % occur in the Lower Alum Shale (3.6 % VRr) and up to 6 % in the Upper Alum Shale (4.4 % VRr). Bands of organic-rich black shales, reflecting sea-level variations controlled by global eustatic cycles, occur within the Tournaisian–Visean “Kohlenkalk”-facies north of the Rhenish Slate Mountains and in the Rügen island area. In both areas the organic matter is characterized by a kerogen Type II + III with TOC contents of up to 7 % and maturities of up to 4.2 and 1.8 % VRr, respectively. Black hemipelagites intercalated with coarser-grained silt- and sandstones occur in the Synorogenic Flysch Formation of the Namurian A along the southern basin margin. TOC contents vary from 0.5 to 2.0 % with Type III kerogen dominated organic matter and maturities of up to 2.5 % VRr. The baseline parameters presented in this paper indicate a shale gas potential for the sediments of the Culm-facies on the southern basin margin and of the “Kohlenkalk”-facies in the Rügen area.     

东尼日尔盆地Tenere坳陷上白垩统海相烃源岩评价及勘探潜力

东尼日尔盆地是中西非裂谷系中典型的中—新生代裂谷盆地。Tenere坳陷位于盆地西北部,包括西部凹陷、东Ⅰ凹陷和东Ⅱ凹陷。对Saha-1井上白垩统岩屑样品的分析揭示,干酪根显微组分以不发荧光或弱荧光的无定形体为主,岩石抽提物中C29甾烷优势明显,说明该井上白垩统泥岩有机质输入以陆源植物为主。岩石热解分析表明上白垩统Yogou组泥岩大多数为中等—好烃源岩,有机质以Ⅱ2-Ⅲ型为主,Donga组泥岩大部分为差—中等烃源岩,以Ⅲ型为主;岩石热解峰温指示烃源岩成熟门限深度为2300 m左右。生烃史模拟显示,Saha-1井Yogou组泥岩尚未开始生烃,Donga组在白垩纪末期开始生烃,下部已进入生气阶段。综合研究认为Tenere坳陷的西部凹陷勘探潜力较大,而东Ⅰ凹陷和东Ⅱ凹陷潜力有限。     

Hydrocarbon source potential and depositional environment of the Surma Group shales of Bengal basin,Bangladesh

Surma Group is the most important geological unit of Bengal basin, Bangladesh, because petroleum resources occur within this group. It is mainly composed of alternation of shale and sandstone and the shale fraction has long been considered as source rocks and the sandstone fraction as reservoir. These source and reservoir rocks have been studied by different authors by different approach but none of them adopted organic geochemistry and organic petrology as a means of study of source rock and their possible depositional environment. A total of thirty shale core samples have been collected from eight different gas fields to fulfill the short coming. The collected samples have been subjected to Source Rock Analysis (SRA) and/or Rock-Eval (RE) followed by pyrolysis gas chromatography (PyGC), gas chromatography mass spectrometry (GCMS), elemental analysis (EA) and organic petrological study such as vitrinite reflectance measurement and maceral analysis. The analyzed organic matter extracted from the shales of Surma Group consists mainly of Type III along with some Type II kerogen. The studied shales are mostly organically lean (TOC ±1%) and the extracted organic matter is fair to moderate. Based on these results, the analyzed shales have been ranked as poor (mostly) to fair quality source rock. The organic matter of the analyzed shale samples is thermally immature to early mature for hydrocarbon generation considering their T_max and measured mean vitrinite reflectance values. The hopane 22S/(22S + 22R), moretane/hopane ratio and sterane parameters are also in good agreement with these thermal maturity assessments. The predominance of odd carbons over even carbons (most common) and/or even carbons over odd carbon numbered n-alkanes, moderate Pr/Ph ratio, low to high Tm/Ts ratio, comparative abundance of sterane C₂₉ (i.e., C₂₉ >C₂₇>C₂₈), Pr/nC₁₇ — Ph/nC₁₈ values, C/S ratio and dominance of vitrinite macerals group with the presence of liptinite macerals demonstrate that the organic matter has derived mainly from terrestrial inputs with an insignificant contribution from the marine sources. The condition of deposition alternates from oxic to anoxic.