Sequence stratigraphic controls on reservoir characterization and architecture: case study of the Messinian Abu Madi incised-valley fill, Egypt

Understanding sequence stratigraphy architecture in the incised-valley is a crucial step to understanding the effect of relative sea level changes on reservoir characterization and architecture. This paper presents a sequence stratigraphic framework of the incised-valley strata within the late Messinian Abu Madi Formation based on seismic and borehole data. Analysis of sand-body distribution reveals that fluvial channel sandstones in the Abu Madi Formation in the Baltim Fields, offshore Nile Delta, Egypt, are not randomly distributed but are predictable in their spatial and stratigraphic position. Elucidation of the distribution of sandstones in the Abu Madi incised-valley fill within a sequence stratigraphic framework allows a better understanding of their characterization and architecture during burial. Strata of the Abu Madi Formation are interpreted to comprise two sequences, which are the most complex stratigraphically; their deposits comprise a complex incised valley fill. The lower sequence (SQ1) consists of a thick incised valley-fill of a Lowstand Systems Tract (LST1)) overlain by a Transgressive Systems Tract (TST1) and Highstand Systems Tract (HST1). The upper sequence (SQ2) contains channel-fill and is interpreted as a LST2 which has a thin sandstone channel deposits. Above this, channel-fill sandstone and related strata with tidal influence delineates the base of TST2, which is overlain by a HST2. Gas reservoirs of the Abu Madi Formation (present-day depth ～3552 m), the Baltim Fields, Egypt, consist of fluvial lowstand systems tract (LST) sandstones deposited in an incised valley. LST sandstones have a wide range of porosity (15 to 28%) and permeability (1 to 5080mD), which reflect both depositional facies and diagenetic controls. This work demonstrates the value of constraining and evaluating the impact of sequence stratigraphic distribution on reservoir characterization and architecture in incised-valley deposits, and thus has an important impact on reservoir quality evolution in hydrocarbon exploration in such settings.     

The use of seismic interpretation for delineating the characteristic features of Messinian channels in the north Nile Delta, Egypt

Abu Madi Messinian Formation occupied a prominent issue as the most exploratory target in the search for natural gas in the Nile Delta. Interpretation of the available onshore seismic reflection data of the northeastern part of the Nile Delta reveals that there is a series of troughs, depressions, and mounded structures within the Abu Madi Formation (Messinian time). Onlap, downlap, and truncation relationship of reflections were observed very close to fault locations in the Miocene time. Many channels have been imaged clearly and described on the seismic reflection data of the onshore Nile Delta. The depths to these channels range between 2.5?s in the southeast to 3.1?s (t.w.t.) while their width ranges from 1?km to more than 5?km. These channels were formed by two factors: (1) submarine erosion and redeposition, during the relative sea level falls and (2) tectonic effect. Many of these channels followed more or less the trends of the historic branches of the ancient Nile Delta. The classification of these channels is based on some factors: (1) channel morphology (depth and width), (2) channel shape, and (3) tectonic effect.     

Hydrocarbon maturation modeling of Paleocene to Lower Miocene source rocks in the Niger Delta Basin: implications for hydrocarbon generation

This study evaluates the hydrocarbon generation potentials and time of generation for Paleocene to Lower Miocene source rock horizons from A-1, B-1, B-2, and C-1 wells in the Niger Delta Basin using 1D Petromod modeling software. Wells A-1, B-1 and B-2, and C-1 are located within the Central Swamp, the Coastal Swamp, and the Shallow Offshore depobelts, respectively. The thermal history was derived from the rifting–subsidence heat flow model. Maturity modeling were carried out by using Easy%Ro kinetic model and a heat flow history predicting present-day heat flow which were calibrated with measured temperature data. Results of the study suggest that these potential source rocks have attained maturity status to generate hydrocarbons, with vast differences existing in the timing of the onset of oil generation. Basin modeling suggests that Paleocene source rocks entered the oil generative window from the Oligocene to Miocene times with thermal maturity window that varies from gas generation to early-mature phase. The Eocene source rocks have also attained maturity from Miocene to Pliocene times, and their thermal maturity ranges from gas generation to early maturity stage. The Oligocene source rocks also began to generate oil during the Miocene and are currently within the early-mature to mid-mature stage. The thermal maturity window for the Lower Miocene source rocks ranges from immature to early-mature stage. The present modeling results reveals that higher levels of thermal maturity are attained in areas with high geothermal gradients and heat flow values while the cooler areas exhibits lower levels of maturation. The onset of the oil window lies at 2859 m at A-1 (Central Swamp), 3240 m at B-2 (Coastal Swamp), 4732 m at B-1 (Coastal Swamp), and 4344 m at C-1 (Shallow Offshore). The depth to the onset of oil window is found deeper in the Shallow Offshore and western parts of the study area than in the eastern and northwestern parts. The result of this study suggest that the Paleocene, Eocene, Oligocene, and Lower Miocene source rocks are the principal source rocks for oil and gas generation in the Niger Delta Basin.     

Hydrocarbon fluid inclusions and source rock parameters: A comparison from two dry wells in the western offshore,India

Fluid inclusions represent the direct evidence of paleofluids and can provide valuable information on the evolution of sedimentary basins and oil-bearing strata. Hydrocarbon fluid inclusion(s) (HCFIs) are the vestiges of oil from the geological formations. The paper delineates the paleotemperature (T_h)/ oil window, the oil quality of HCFIs and Raman peaks corresponding to hydrocarbon species of HCFIs using fluid inclusion techniques, and source rock potential of hydrocarbon generation, thermal maturity, the quantity of organic matter, and the kerogen types obtained through Rock-Eval pyrolysis data from two dry wells RV-1 well of Mumbai offshore and KKD-1A well of Kerala-Konkan Basin. The present study compares the fluid inclusion parameters as well as the source rock geochemical characteristics of these two dry wells to address the scientific problem of the wells going dry. Further, evaluated whether the results agree with an earlier finding from a case study of two wells named KK4C-Al (Kerala-Konkan basin) and RV-1 well where only a few parameters such as temperature of homogenization (T_h) & API gravity were utilised, and the chances of getting oil in the nearby areas of these two wells were reported. In the present study, the fluid inclusion parameters such as the palaeotemperature (T_h), API Gravity and Raman spectra were obtained from micron sized fluid inclusions at different depths for a quick assessment of nature of oil inclusions within the two dry wells. Along with fluid inclusion parameters, different source rock parameters obtained from Rock-Eval Pyrolysis analysis (secondary data) such as S1, S2, S3, T_max, Hydrogen Index (HI), Oxygen Index (OI), Potential Yield (PY), Production Index (PI) and Total Organic Carbon Content (TOC) were also considered for a detailed source-rock evaluation of two wells (RV-1 and KKD-1A) and the results act as the supporting evidence to address the reason for the wells gone dry.Temperature of homogenisation (T_h) of hydrocarbon Fluid Inclusion Assemblages (FIAs) from both the wells fall in the oil window (60–150 °C) range indicating that there was a conducive thermal condition favourable for oil generation in these two basins. API gravity of oils in RV-1 well of Mumbai offshore (48–53) was lighter when compared to those in KKD-1A (18–22) of Kerala-Konkan basin. Raman spectra of HCFI samples could decipher important hydrocarbon species from RV-1 well samples. Raman spectra of KKD-1A well show less prominent peaks (broad) only. Pyrolysis data shows that Paleocene–Early Eocene source rocks of Panna formation of RV1 well are mature enough to generate hydrocarbons. On the other hand, Paleocene aged source rocks of Kasargod formation of KKD-1A well are immature. Source rock maturity therefore could be considered as crucial in hydrocarbon generation in these two wells even if oil-window was achieved. This study reports that, in RV-1 well, even though it is a dry well in a proven basin, the oil window, API gravity of oils and constituents from HCFIs of RV-1 well and the source-rock maturity opens up a demand for detailed exploration in nearby areas of RV-1 in the Mumbai offshore basin hopeful of finding a high-value prospect for oil, whereas the fluid inclusion studies in the HCFIs of KKD-1A well of Kerala-Konkan basin is showing only a minimal chance of oil generation that too of a heavy nature and the source rock immature characteristics suggesting only minimal generation of hydrocarbons. Due to the heaviness of the available oil in the KKD-1A well impedes migration. Our study suggests that there is no potential for finding oil in the nearby areas of KKD-1A well of Kerala-Konkan basin.     

南黄海南部坳陷下第三系阜宁组、戴南组泥岩的粘土矿物与热成熟度的关系

粘土矿物在埋藏成岩过程中的重要变化是膨胀型粘土逐渐减少(如蒙脱石),伊利石、绿泥石结晶度逐渐增加(半高宽减小)。通过对具有代表性的常6—1—1井粘土矿物X衍射分析,系统研究了伊利石10A峰、绿泥石7A峰的半高宽、A/H值(背影峰面积/峰高)与镜质体反射率R_0以及有机质热变指数LOM的对应关系。研究结果表明伊利石(特别经乙二醇处理过)的10A峰半高度及A/H值可以估算有机质成熟与否;可以作为预测源岩生油门限以及油气保存阶段的指标。     

Palynofacies and hydrocarbon generation potential of the upper Triassic Kurrachine Formation and lower part of the Baluti Formation, Mosul Block, Northwestern Iraq

Three exploration wells were selected near Mosul city (Az-29, Bm-15, and Kd-1) to study the palynozones and hydrocarbon generation potential of the Upper Triassic Baluti and Kurrachine Formations. This study was completed in two phases: The first was a study of palynofacies and their paleoenvironmental indications, degree of preservation, diversity of palynomorphs, and organic maturity of the rocks according to palynomorphs’ color using a refracted light microscope. More than 80 slides of organic matter were used for this study. Four palynofacies were tentatively recognized. (1) The first palynofacies is diagnostic of the Baluti Formation in the Az-29 and Kd-1 wells; (2) The second palynofacies appeared at different depths in the Kurrachine Formation in three wells. (3) The third was only found between the depths of 4,534 to 4,685 m in the well Az-29. (4) The fourth was only found between 3,500- and 3590-m depth in the well Bm-15. A distal coastal marine environment is suggested for the Baluti Formation and restricted lagoonal environment for the Kurrachine Formation. The second phase used organic geochemical analyses to confirm the suggested paleoenvironmental and hydrocarbon generation material. Three techniques were used, namely total organic carbon, pyrolysis, and pyrolysis gas chromatography, on more than 35 samples from different depths in three wells. The analyses proved that a sufficient quantity of organic matter occurs that and has suitable maturity for hydrocarbon generation potential of oil and gas.     

Geochemical characterization of source rock from the north bank area,upper Assam basin

The study area is confined to a part of upper Assam basin, north of river Brahmaputra (north bank). Seven exploratory wells have been drilled in this part of the basin in order to probe the hydrocarbon prospects of the area. The exploratory efforts did not indicate significant hydrocarbon prospects in the north bank. Since the presence of source rock is an important component of the petroleum system, a detailed systematic study of source rock potential was carried out by analysing known source rock intervals in these seven wells. In the present study, Rock-Eval pyrolysis combined with specific geochemical analyses like GC and TLCFID has been used to characterise the source rocks, their distribution and thermal maturity of the organic matter. The source rocks in the area show mainly Type III, land-plant derived organic matter along with some Type II organic matter. They are predominantly gas prone in nature, although mixed and oil-prone source rocks are occasionally present. Although source rock intervals have been identified in the Langpar, Sylhet limestone and Kopili formations, the Barail Group and the Tipam sandstone Formation, the bulk of the source rock occurs within the Kopili Formation. Geochemical analyses of the cores indicate oil signatures at certain depths, although no commercial oil was discovered. The hydrocarbon generation potential of these source rocks are constrained by low maturity at the presently drilled depths.     

Organic geochemistry of Miocene source rocks from the Banat Depression (SE Pannonian Basin, Serbia)

The origin, depositional environment and maturity of petroleum source rocks were determined via conventional whole rock and biomarker analysis of samples from wells in the Banat Depression, where the most important Serbian oil and gas fields are located. The organic matter (OM) in organic-rich upper Tertiary siltstones and marls consists predominantly of Type II kerogen. Numerous biomarker parameters indicated mixed algal-terrestrial OM, related to a brackish or freshwater environment, whose salinity decreased from Middle to Upper Miocene. The OM was deposited under variable redox conditions, reducing to sub-oxic.The wells in the Banat Depression experienced variable high rates of rapid heating, providing an opportunity for examining the applicability of different thermal indicators in a hyperthermal basin. Rock-Eval and numerous biomarker parameters indicate that the main stage of oil generation begins at ca.130 °C and vitrinite reflectance (Rc) ca. 0.63% and reaches a maximum at ca.145-150 °C and Rc ca. 0.72-0.75%, while the late stage of oil generation starts at ca.155 °C and ca. Rc 0.78%, which corresponds, depending on geothermal gradient, to relative depths of 2100-2300 m, 2600-2900 m and 3050-3100 m, respectively. The naphthalene and phenanthrene maturity parameters proved to be less applicable than the biomarker ratios, particularly in the early to moderate maturation range. The newly proposed parameter C(14a)-homo-26-nor-17α(H)-hopane/C₃₀hopane (C₃₀HH/C₃₀H) proved applicable to a wide range of maturity.     

恢复地层剥蚀厚度的最优化方法

传统的恢复地层剥蚀厚度的方法是利用钻井、声波和地震资料。但限于各种地质条件而不能广泛应用。本文采取最优化方法,在计算成熟度的数学模型基础上,根据剖面上实测R。值实现对热史的反演求得剥蚀厚度。     

Organic geochemical evaluation of Cretaceous shale samples from the Orange Basin,South Africa

Organic geochemical evaluation of thirty-two Aptian to Campanian shale samples from seven wells drilled on the shelf of the Orange Basin (southwestern Atlantic margin) was carried out in order to determine their origin, depositional environment, thermal maturity and hydrocarbon potential. The shale samples, selected to represent highstand, lowstand and transgressive systems tracts, were analysed by Rock–Eval pyrolysis for total organic C characteristics and by gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) for n-alkanes, aliphatic isoprenoid hydrocarbons and biomarkers (steranes, hopanes and tricylic terpanes). For most of the shale samples Rock–Eval data, hydrogen (HI) and oxygen index (OI) point to mainly Type III terrigenous organic matter. Only a few samples of Turonian age reveal a higher proportion of marine organic matter being classified as Type II/III or Type II. Biomarker parameters suggest that the samples are deposited under suboxic to oxic environmental conditions. Rock–Eval data and biomarker maturity parameters assign for most of the samples a maturity level at the beginning of the oil window with some more mature samples of Aptian, Albian and Cenomanian age. The hydrocarbon generation potential is low for most of the shelf shales as indicated by the S2/S3 ratio and HI values. Exceptions are some samples of Turonian and Aptian age.     

Maximizing the management of groundwater resources in the Paris–Abu Bayan reclaimed area,Western Desert,Egypt

The Paris–Abu Bayan area located along the Darb El Arbaein road is involved in the New Valley Project in the Egyptian Western Desert (EWD) as part of ongoing efforts since the 1960s. In this dryland area, groundwater stored in the Nubian Sandstone Aquifer System (NSAS) serves as the only water resource for a number of different uses. A major concern is the significant groundwater withdrawals from 74 pumped wells since the beginning of agricultural activities in 2000. The recent rapid expansion of agricultural activity and the lack of sufficient groundwater recharge as a result of unplanned groundwater development have led to severe stress on the aquifer. Field measurements have shown a rapid decline in groundwater levels, creating a crisis situation for this sole source of water in the area. In this study, mathematical modeling of the groundwater system (single aquifer layer) of the Paris–Abu Bayan reclaimed area was implemented using MODFLOW to devise a new strategy for the sustainable use of groundwater, by applying a number of scenarios in a finite-difference program. The conceptual model and calibration were developed by generating and studying the hydrogeological records, NSA parameters, production wells, and water level measurements for 2005 and 2012. Three management scenarios were applied on the calibrated model to display the present and future stresses on this aquifer over a 30-year period (2012–2042). The results clearly show a high decline in the heads of the NSA, by about 13.8 m, due to the continuous withdrawal of water (first scenario: present conditions, 102,473 m³/day). In the second scenario, the water level is expected to decrease significantly, by about 16 m, in most of the reclamation area by increasing the pumping rates by about 25% (over-pumping) to meet the continuous need for more cultivation land in the area. To reduce the large decline in water levels, the third plan tests the aquifer after reducing the water withdrawal by approximately 25%, applying modern irrigation systems, and suggesting two new reclaimed areas in the northeastern and northwestern parts (areas 1 and 2), with 20 new wells, at 500 m³/day/well. The results in this case show that groundwater levels are slightly decreased, by about 9.5 m, while many wells (especially the new wells in the northern part) show a slight decrease in groundwater levels (0.8 m). The results comparison shows that the groundwater level in the modeled area is lowered by 0.3 m/year with an increase in the number of wells to 94 and increased cultivation area by about 18% (third scenario), versus 0.45 m/year and 0.60 m/year recorded for the first and second scenarios, respectively. Therefore, based on the results, the third scenario is recommended as a new strategy for improving groundwater resource sustainability in the region.     

东台坳陷现今地温场特征与油藏分布关系

东台坳陷为中国东部苏北盆地油气资源最丰富的地区。为了加深对东台坳陷地温场和油藏关系的理解,根据符合地温场研究要求的54口井连续测温资料和243口井试油温度数据,获得了深度1000～3500m地温、E2s-K2t各层位界面地温和各层地温梯度。地温场分布以凹陷或次凹成独立单元,地温随深度加深而线性增高,地温异常不明显。地温梯度总体呈现"浅层低、深层高"的特点,E2s-E2d地温梯度总体在22～30℃/km之间,E1f-K2t在28～38℃/km之间,平均约为30℃/km。不同深度的地温和地温梯度分布模式相似,正向构造单元高,负向构造单元低;而不同层位的地温分布规律则相反,即凹陷内温度高,凸起和隆起上的温度低。基底构造形态、沉积盖层厚度、深大断裂、地下水、地层放射性生热等因素决定了该坳陷总体为温盆特征。大部分地区目前还处在油气液态窗内,绝大多数油藏分布高于60℃的油气勘探开发黄金区域。     

Organic and organometallic compounds in estuarine sediments from the Gulf of Mexico (1993–1994)

Sediment samples from 281 estuarine sites in the Gulf of Mexico were collected in 1993–1994 and analyzed for several classes of organic and organometallic compounds as part of the Environmental Monitoring and Assessment Program of the United States Environmental Protection Agency. Polynuclear aromatic hydrocarbons (PAHs) were the contaminant class found most frequently and in the highest concentrations; the sum of 24 congeners (ΣPAHs) ranged from <5 ng g^?1 to 15.500 ng g^?1 (dry wt basis). A low percentage of samples (3.9%) exceeded 2000 ng g^?1 ΣPAHs, and only six samples (2.1%) exceeded 4000 ng g^?1, a level above which adverse biological effects may be expected to occur. Less than 4% of sediments exceeded 20 ng g^?1 for the sum of 20 polychlorinated biphenyls (ΣPCBs) and only four samples (1.4%) exceeded 20 ng g^?1 for the sum of several organochlorine pesticides (ΣOCPs). A sample from Freeport Harbor, Texas, contained 4230 ng g^?1 ΣPAHs, 322 ng g^?1 ΣPCBs, and 49.6 ng g^?1 ΣOCPs. Tributyltin exceeded 100 ng g^?1 in only four samples, all of which were from stations in Corpus Christi Bay or Galveston Bay in Texas. The detection of a suite of organophosphate pesticides was very rare and did not exceed 15 ng g^?1. Sediments from the tidally influenced section of the Mississippi River in Louisiana contained low to moderate levels of all classes of organic compounds. The most contaminated sites were in urban estuaries (e.g., Corpus Christi, Galveston, and Pensacola (Florida bays), underscoring the need to concentrate future monitoring and assessment efforts at the regional and local level.     

济阳坳陷古近系沙河街组页岩有机质热演化特征

钻探显示渤海湾盆地济阳坳陷古近系沙河街地层具有良好的页岩油资源潜力,成熟页岩厚度超过1 000 m,其有机质热演化特征备受关注。通过对研究区5口页岩油钻井岩石热解地化参数详细统计和对烃源岩原始有机碳、可转换碳、页岩含油量以及生烃潜力等页岩有机质特征的分析,探讨了页岩镜质体反射率动力学应用范畴。沙河街组（沙三段下亚段和沙四段上亚段）页岩最大热解温度（Tmax）为423～450 ℃,有机质成熟度（Ro）为0.45%～0.94%,平均为0.73%,Ⅱ型烃源岩原始有机碳（TOCo）含量为0.92%～5.67%,平均为4.23%,可转换碳（Cc）比例为51%～63%,平均为59%,页岩含油量(S1)为（10～75）×104 t/km2,平均为39.67×104 t/km2,生烃潜力(S2)为（20～465）×104 t/km2,平均为293×104 t/km2,热解产量指数(PI)为0.03～0.47。综合研究认为,济阳坳陷沙河街组优质烃源岩主要集中在东营凹陷和沾化凹陷,有机质成熟度对页岩油的生成和聚集至关重要,当Ro为0.70%～0.74%时,油气开始大量生成,并且开始排烃。     

Programed oil generation of the Zubair Formation, Southern Iraq oil fields: results from Petromod software modeling and geochemical analysis

1D petroleum system modeling was performed on wells in each of four oil fields in South Iraq, Zubair (well Zb-47), Nahr Umr (well NR-9), West Qurna (well WQ-15 and 23), and Majnoon (well Mj-8). In each of these fields, deposition of the Zubair Formation was followed by continuous burial, reaching maximum temperatures of 100°C (equivalent to 0.70%Ro) at depths of 3,344–3,750 m of well Zb-47 and 3,081.5–3,420 m of well WQ-15, 120°C (equivalent to 0.78%Ro) at depths of 3,353–3,645 m of well NR-9, and 3,391–3,691.5 m of well Mj-8. Generation of petroleum in the Zubair Formation began in the late Tertiary, 10 million years ago. At present day, modeled transformation ratios (TR) indicate that 65% TR of its generation potential has been reached in well Zb-47, 75% TR in well NR-9 and 55-85% TR in West Qurna oil field (wells WQ-15 and WQ-23) and up to 95% TR in well Mj-8, In contrast, younger source rocks are immature to early mature (<20% TR), whereas older source rocks are mature to overmature (100% TR). Comparison of these basin modeling results, in Basrah region, are performed with Kifle oil field in Hilla region of western Euphrates River whereas the Zubair Formation is immature within temperature range of 65–70°C (0.50%Ro equivalent) with up to 12% (TR?=?12%) hydrocarbon generation efficiency and hence poor generation could be assessed in this last location. The Zubair Formation was deposited in a deltaic environment and consists of interbedded shales and porous and permeable sandstones. In Basrah region, the shales have total organic carbon of 0.5–7.0 wt%, Tmax 430–470°C and hydrogen indices of up to 466 with S2?=?0.4–9.4 of kerogen type II & III and petroleum potential of 0.4–9.98 of good hydrocarbon generation, which is consistent with 55–95% hydrocarbon efficiency. These generated hydrocarbons had charged (in part) the Cretaceous and Tertiary reservoirs, especially the Zubair Formation itself, in the traps formed by Alpine collision that closed the Tethys Ocean between Arabian and Euracian Plates and developed folds in Mesopotamian Basin 15–10 million years ago. These traps are mainly stratigraphic facies of sandstones with the shale that formed during the deposition of the Zubair Formation in transgression and regression phases within the main structural folds of the Zubair, Nahr Umr, West Qurna and Majnoon Oil fields. Oil biomarkers of the Zubair Formation Reservoirs are showing source affinity with mixed oil from the Upper Jurassic and Lower Cretaceous strata, including Zubair Formation organic matters, based on presentation of GC and GC-MS results on diagrams of global petroleum systems.     

Characteristics of Piezometric heads and determination of fresh water–salt water interface in the coastal zone near Beihai,China

Changes in hydraulic heads with space and time and evolution of the location of fresh water–salt water interface are important for groundwater development in coastal aquifers. Measurements of piezometric heads at 11 well clusters consisting of three piezometric wells of different depths with a 5-day interval for 15 months show that the piezometric heads at nearly all the wells near the northwestern coast in Beihai decrease with increasing depth and increase with increasing distance from the coast. Changes in piezometric heads at the wells during the measurement period were caused by seasonal precipitation and induced by the tide. The depth of the sharp interface between fresh water–salt water can be estimated based on measurements of piezometric heads at a piezometric well tapping at a point in the salt water zone below the interface and measurements of the water table at the same well. The calculations of the interface for well H5 range from 40 to 80 m below sea level in the measurement period, which are believed to be more reasonable than those estimated with the Ghyben–Herzberg relation. An erratum to this article can be found at     

The analysis of oil trapped during secondary migration

During secondary migration, there is an opportunity for oil to be trapped as fluid inclusions (FIs) within framework grains such as quartz and within diagenetic cements that have a crystalline structure. Oil saturation on migration pathways remains relatively low, so typically fewer oil inclusions get trapped compared with samples from an oil column. Geochemical analysis of the much smaller amounts of inclusion oil present in samples from interpreted oil migration pathways has been attempted for two samples from the Champagny-1 and Delamere-1 wells in the Vulcan Sub-Basin, northern offshore Australia. A combination of petrographic analysis, bulk geochemical inclusion analysis and log evaluation confirmed that both samples were from oil migration pathways. Despite the small number of oil inclusions, reliable geochemical data were acquired from both samples that were significantly above the levels detected for the system and outside-rinse blanks. The FI oil trapped on the interpreted oil migration pathway in Champagny-1 was generated from clay-rich marine source rock with little terrigenous organic matter input. It was generated at peak oil window maturity and correlates best with oils derived from the Late Jurassic Lower Vulcan Formation. In contrast, the Delamere-1 FI oil contains evidence of greater input of terrigenous organic matter and was generated at early oil window maturity. This FI oil also contains a signature of a biodegraded component, which could have been generated either from the Middle Jurassic Plover Formation, or from an older source rock. These data indicate that it is feasible to geochemically map migration pathways across prospects or basins, and to analyse palaeo-oil compositions in oil zones where the few inclusions get trapped. This also suggests that the few oil inclusions that sometimes occur in Proterozoic or Archaean rocks may be analysable in the future, which would provide relatively pristine and robust data on the composition and diversity of Earth’s early biosphere.     

Hydrocarbon potential of the Sargelu Formation,North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg?HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI?=?3^? to 3⁺, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R₂₈ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.     

康滇地轴中南段牟定1101铀矿区沥青铀矿成矿时代及成因

牟定1101铀矿区是康滇地轴中南段发现高品位、巨粒晶质铀矿代表性产地之一.为了解铀矿物的形成时代及成因,利用微区、原位分析技术（EPMA、SEM、LA-ICP-MS）对该区3件沥青铀矿样品开展了主量化学成分、稀土元素分析及年龄测定.沥青铀矿电子探针（EPMA）化学成分具有高PbO、ThO₂、Y₂O₃,低SiO₂,Na₂O,CaO,K₂O,ZrO₂含量特征,反映沥青铀矿形成之后遭受后期的蚀变、改造作用较弱.沥青铀矿的稀土元素ΣREE-（U/Th）、ΣREE-（ΣREE/ΣREE）_N图解表明其为岩浆作用相关成因、形成于高温环境（T>450℃）.3件沥青铀矿的U-Pb同位素年龄在（950±5 Ma、MSWD=0.025,953±9 Ma、MSWD=0.051,954±8 Ma、MSWD=0.085）之间,表明它们具有相近的形成时代（新元古界晚期）.对比国外不同类型铀矿床,该区的铀成矿作用具有岩浆成因特征.新元古界晚期,Rodinia超大陆由聚合转化为裂解阶段,广泛引起了Pt₁j苴林群发生区域变质、混合岩化、铀成矿作用.牟定1101铀矿区的成矿作用与~960 Ma Rodinia超大陆裂解地质事件所对应的晋宁构造运动有关.      

Monitoring artificially stimulated fluid movement in the Cretaceous Dakota aquifer,western Kansas

Aquifer properties can be evaluated by monitoring artificially stimulated fluid movements between wells, if the fluid is heated. Changes in the temperature profile recorded in observation wells indicate the flow path of the heated fluid, which in effect acts as a tracer. A fluid-flow experiment in the Cretaceous Dakota Formation at the Hodgeman County site, west-central Kansas, demonstrated the advantage of using the distributed optical-fiber temperature sensing method for monitoring transient temperature conditions in this hydrological application. The fluid flow in the aquifer was increased by producing water from a pumping well and injecting heated water in an injection well 13 m (43 ft) distant from the pumping well. The time-temperature series data obtained and compared with results from previous pumping tests point to interwell heterogeneity of the aquifer and to a zone in the sandstone aquifer of high hydraulic conductivity. However, the experiment would have allowed further clarification of aquifer heterogeneity and thermal properties if at least one observation well had been present between the injection and production wells. Electronic Publication