bluuebunny/crossref_metadata_2025_split huggingface dataset:
THE GEOCHEMICAL COMPOSITION OF OILS FROM PALAEOZOIC RESERVOIRS IN THE SE WEST SIBERIAN BASIN
Authors: Serebrennikova O. V. , Filippova T. Ju. , Devyatov V. P. 
Published: March 2006

We present organic geochemical data (vanadyl and Ni‐porphyrin contents, pristane/phytane ratios and n‐alkane compositions) relating to oils from Palaeozoic reservoirs in the SE West Siberian Basin. Analogous data from organic material in Palaeozoic and overlying Jurassic source rocks is also presented. The Jurassic succession here consists of siliciclastic units deposited during alternating marine transgressions and regressions. Our results indicate that vanadyl and Ni‐porphyrins occur predominantly in transgressive units, and that pristane/phytane ratios increase progressively up through the Jurassic section. However, for Jurassic sediments in which vanadyl porphyrins are present, the Pr/Ph ratio is strongly facies dependent and is relatively high in transgressive units and lower in regressive units. By contrast, (C21+C23+C25)/3C20 n‐alkane ratios are relatively low in transgressive deposits and higher in regressive deposits. There is a close relationship between this parameter and Pr/Ph ratio.Oils from weathered Palaeozoic reservoirs have variable compositions. In most cases, these compositions appear to be influenced by the depositional characteristics of the overlying Jurassic source intervals. Our data point to a mainly Jurassic origin for the oils in SE Western Siberia. However there is some evidence that a Palaeozoic source may be significant in the south of the studied area.
ORGANIC FACIES, DEPOSITIONAL ENVIRONMENT AND PETROLEUM GENERATING CHARACTERISTICS OF THE LACUSTRINE SHAHEJIE FORMATION, ES4 MEMBER, WESTERN DEPRESSION, LIAOHE BASIN (NE CHINA)
Authors: Fuhrmann A. , Horsfield B. , Lòpez J. F. , Hu Liguo , Zhang Zhanwen 
Published: March 2006

Organic petrological and organic geochemical investigations have been carried out on Eocene lacustrine deposits from the Western Depression of the Liaohe Basin (NE China). The purpose was to conduct a systematic organofacies classification of these rocks, to determine their source rock potential and hydrocarbon characteristics, and to study depositional processes within this palaeo‐lake setting. Rock‐Eval data and molecular biomarkers indicate that samples analysed were immature in terms of thermal maturation.Three distinct organofacies have been identified within the ES4 member of the Shahejie Formation. The depositional model envisages the formation of good to excellent oil‐prone source rocks in a shallow saline‐alkaline lake with a stratified water column; of source rocks with moderate source potential in a deep and freshwater lake; and of poor quality source rocks towards the lake margins.The shallow lake organofacies is characterised by high total organic carbon contents (up to 17.6%) and high Hydrogen Index values (up to 908 mg HC/g TOC). The laminated sediments contain elevated amounts of fluorescing amorphous organic matter (OM) and lamalginite. High primary production dominated by cyanobacteria together with anoxic bottom waters and a paucity of terrestrial vegetation in an arid climate resulted in the deposition of Type I OM. The presence of monoaromatic carotenoids, typically derived from photosynthetic purple and green sulphur bacteria Chromatiaceae and Chlorobiaceae, suggests a water body in which an anoxic photic zone occurred at least periodically. The source rocks deposited in this type of lake have the potential to generate high‐wax paraffinic petroleum at high subsurface temperatures (up to 159°C at a heating rate of 5.3° C/million years).The quality and quantity of the OM within the freshwater organofacies (Shale I, Shale II) were determined to be lower. Petrologic observations point to the absence of laminations and the presence of Botryococcus braunil telalginite. The abundance of lycopane and its aromatised abundance of lycopane and its aromatised diagenetic analogues confirmed the presence of this algal species. Generally low concentrations of gammacerane and high pristane/phytane ratios indicate a low salinity, hydrologically open environment in which oxic conditions generally prevailed, resulting in relatively poor preservation of OM.Sediments of poor source rock quality deposited in the marginal fan‐delta setting (the Shu‐Du area) can be distinguished visually by the presence of terrigenous particles (vitrinite, inertinite and terrigenous liptinites), and geochemically by the presence of phenols in the pyrolysates.
POTENTIAL STRUCTURAL TRAPS ASSOCIATED WITH LOWER CARBONIFEROUS SALT IN THE NORTHERN TARIM BASIN, NW CHINA
Authors: Zhou Jiangyu , Lin Zhongmin , Luo Chuangrong , Wang Xiepei 
Published: March 2006

In the Aixieke‐Santamu area of the northern Tarim Basin (NW China), 45 relatively low amplitude structures related to the plastic flow of Lower Carboniferous salt have been discovered in the Lower Carboniferous Kalashayi Formation and the Middle‐Upper Triassic Akekule and Halahatan Formations. Three small hydrocarbon accumulations have so far been located at the margins of a Lower Carboniferous salt body (measuring about 55km x 75km and 115–225m thick, controlled by wells and 2D and 3D seismic sections). In this paper, we consider the development of this salt body and discuss possible reasons why vertical diapirs are absent from the study area. We attempt to develop a model of salt flow and we investigate the relationship between salt flow and the occurrence of oil and gas traps.Using recently‐acquired high‐resolution 2D and 3D seismic profiles, we show that the Lower Carboniferous salt has undergone three separate phases of plastic flow. At the end of the Early Permian, the salt flowed southwards by 2.0–2.8 km; then, during the Late Triassic—Early Jurassic, it flowed in the same direction by 1.0–1.8 km; and finally at the end of the Tertiary, it flowed northwards by 0.6–1.5 km. These movements resulted in the formation of various types of structural trap in the Kalashayi, Akekule and Halahatan Formations including salt ridge anticlines, domes and marginal troughs. Salt ridge and salt edge low‐amplitude anticlines are probably the most important targets for future hydrocarbon exploration.
NASARA‐I WELL, GONGOLA BASIN (UPPER BENUE TROUGH, NIGERIA): SOURCE‐ROCK EVALUATION
Authors: Obaje N. G. , Wehner H. , Abubakar M. B. , Isah M. T. 
Published: March 2006

Well Nasara‐I, one of three exploration wells recently drilled in the Gongola Basin in the Upper Benue Trough (onshore Nigeria), was tested and found to be dry. The well penetrated an entirely Cretaceous succession comprising the Pindiga, Yolde and? Bima Formations, and standard organic geochemical analyses were carried out to assess the source‐rock potential of selected samples. Total organic carbon (TOC) contents were found generally to be very low, with no values exceeding 1.0wt%, and about one‐half of them ranging between 0.50 and 0.87wt%. Hydrogen indices (Hls) correlated against Tmax indicate some gas‐generative potential.However, in the depth interval between 4,710ft and 4,770ft, TOC values of between 52.1 and 55.2 wt% were recorded; these are characteristic of coals. This is the first report of a coal within the Pindiga, Yolde or Bima Formations. Hls were between 564 and 589 mgHC/gTOC and Tmax was 423–428°C. Although hydrogen indices can be misleading in assessing the oil‐generative potential of a coal, values as high as those recorded in Nasara‐I permit oil‐generative capabilities to be inferred.Total ion chromatograms of the saturated hydrocarbon fractions of the coaly samples show some ramping of unresolved complex mixtures attributable to biodegradation. Further biomarker data indicate a dominance of low molecular weight n‐alkanes (C15–C25), pristane/phytane ratios of 0.8 to 1.3, and very high contents of C28 regular steranes. These attributes, together with the very high Hls, indicate that some oils generated from a probably deeper‐seated or laterally‐located (and yet to be identified) lacustrine source rock must have migrated and been adsorbed into the coaly facies, which were later intermittently subjected to anoxic to suboxic biodegradation processes.
EXPERIMENTAL VERIFICATION OF OIL SATURATION AND LOSSES DURING SECONDARY MIGRATION
Authors: Luo X. , Zhang F. , Miao S. , Wang W. , Huang Y. , Zhou B. , Loggia D. , Vasseur G. 
Published: March 2006

Accurate estimates of losses occurring during secondary petroleum migration are of vital importance for valid petroleum systems assessments. In this paper, we discuss the development of migration pathways and the corresponding hydrocarbon losses using data from laboratory experiments based on diphasic immiscible draining processes. These experiments permitted us to study the formation of migration pathways, the distribution of non‐wetting oil along these pathways, and the re‐utilization of existing pathways by later pulses of migrating oil.The configuration of a migration pathway can be characterized by a phase diagram whose coordinates are two dimensionless numbers: the capillary number and the Bond number (a measure of the buoyancy force). NMR imaging was used to measure the saturation of residual oil within the pathways. It was found that, after migration, the average residual oil saturation within a pathway was generally less than 40% at a resolution of 0.4mm. Hydrocarbon losses during migration were estimated as the product of the volumetric proportion of the migrating cluster structure, defined using this spatial resolution, multiplied by the average residual oil saturation in the pathway.
THE HYDROCARBON POTENTIAL OF LEBANON: NEW INSIGHTS FROM REGIONAL CORRELATIONS AND STUDIES OF JURASSIC DOLOMITIZATION
Authors: Nader F. H. , Swennen R. 
Published: March 2006

This paper presents an updated review of the petroleum prospects of Lebanon. We briefly describe the known hydrocarbon shows in Lebanon and compare them with adjacent countries, leading to the construction of a model for hydrocarbon migration which takes into account regional facies and reservoir correlations.The oldest exposed rocks in Lebanon are the Jurassic carbonates of the Kesrouane Formation (over 1,000m thick). This formation can be divided into a basal unit dominated by seepage‐reflux stratabound dolostones (the Chouane Member,) and an overlying limestone‐prone unit (the Nahr Ibrahim Member). A two‐stage dolomitisation model for the Jurassic carbonates in Lebanon has recently been proposed by the authors. According to this model, second‐stage Late Jurassic hydrothermal dolomitisation is believed to have occurred as a result of the circulation of mixed dolomitising fluids along faults. Hence, the resulting dolostones are fault‐controlled and strata‐discordant, and may occur at any level within the Kesrouane Formation, locally redolomitising the Chouane Member dolostones and replacing the Nahr Ibrahim Member limestones. In this paper, we discuss the implications of diagenesis (especially dolomitisation) on the petroleum prospects of the Kesrouane Formation in Lebanon. The hydrothermal fault‐related dolostones possess porosities of up to 20%, which result from intercrystalline and mouldic porosity enhancement. Porosities in the stratabound reflux dolostones (Early Jurassic) and limestones are much lower.The fact that most of the Jurassic system in onshore Lebanon was affected by meteoric diagenesis during the Late Jurassic ‐ Early Cretaceous and the Cenozoic may downgrade hydrocarbon prospectivity. However, offshore areas far from the meteoric realm may have been less (or not at all) affected by meteoric invasion. If effective seals are present there, these areas may host promising Jurassic reservoir units.We also review the prospectivity of unexposed Triassic potential reservoir units in onshore Lebanon (e. g. the “Qartaba” structure). By analogy with the Syrian portion of the Palmyride Basin, Triassic strata here may include both reservoir units and evaporite seals.
GEOCHEMICAL SIGNIFICANCE OF SEEPAGE OILS AND BITUMINOUS SANDSTONES IN THE ALBERTINE GRABEN, UGANDA
Authors: Lirong Dou , Dingsheng Cheng , Jianjun Wang , Rubondo Ernest N. T. , Kasande Robert , Byakagaba Abdul , Mugisha Frank 
Published: March 2006

Geochemical analysis of surface samples comprising three seepage oils, two bituminous sandstones and five shales collected from the Ugandan portion of the Albertine graben (a Cenozoic rift basin in Eastern Africa) indicates that the basin may have some petroleum potential. The analyses show that seepage oils from the Kibiro and Paraa localities were derived from Types I or II1 source rocks, deposited in semi‐deep or deep‐water lacustrine environments containing abundant freshwater algae. However, the seepage oil from Kibuku is derived from a Type III source rock.A comparison of the seepage oils and the bituminous sandstones suggests that there are at least two sets of mature or threshold‐mature source rocks in the Albertine graben — one in the Upper Tertiary and the other in the underlying (pre‐Upper Tertiary) succession. According to molecular indicators of maturity, the Kibiro seepage oil was generated during peak maturation, whereas the Paraa and Kibuku seepage oils are of lower or threshold maturity.This work was completed under the supervision and guidance of Qingping Li, Chief Engineer of CNODC; Xiaoguang Tong, Chief Geologist of CNODC; and Reuben Kashambuzi, Commissioner, PEPD, MEMD, Uganda. The Embassy of the People's Republic of China in Uganda assisted with the completion of the project. Professors Tieguan Wang and Lihua Chen reviewed the research results, respectively. CNODC and the Ugandan authorities (PEPD) provided the favourable conditions for this project. Journal review was by Roger Swart (Namcor, Namibia) and Andrew Carr (Advanced Geochemical Systems Ltd) whose comments on the manuscript are acknowledged with thanks.
THEGIBRALTARDISCOVERY, NORTHERN LLANOS FOOTHILLS, COLOMBIA: CASE HISTORY OF AN EXPLORATION SUCCESS IN A FRONTIER AREA
Authors: Villamil T. , Muñoz J. , Sánchez J. , Aristizabal J. J. , Velasco J. , Luna P. E. , Mantilla A. , Fajardo A. , Peña L. E. , Paz M. G. , Silva O. , Sánchez E. , Meza N. 
Published: March 2006

Ecopetrol's recent Gibraltar discovery was made in a previously little known area of the northern Llanos foothills of the Eastern Cordillera of Colombia. The structure at Gibraltar is complex and comprises a thrust stack with which are associated hangingwall anticlines providing four‐way closures (or three‐way against a sealing fault). The Gibraltar‐I well was originally drilled by Occidental in 2002. According to Ecopetrol's subsequent structural reinterpretation, this well penetrated the back limb of a fault propagation fold. This structural model was confirmed with a sidetrack well which penetrated the Palaeocene Barco Formation and demonstrated the presence of light hydrocarbons.A second objective of well re‐entry at Gibraltar was to investigate the Eocene Mirador Formation, a major reservoir unit elsewhere in the Llanos foothills, in case of missed or bypassed pay. Tests of the Mirador Formation verified the presence of high quality 57° API degree condensate that flowed at a rate of 690 barrels per day together with 44 million cubic feet of rich gas per day.The success at Gibraltar will hopefully encourage further exploration developments in this remote and structurally‐complex region.
STRATIGRAPHY, DEPOSITIONAL SETTING AND RESERVOIR CHARACTERISTICS OF TURONIAN ‐ CAMPANIAN CARBONATES IN CENTRAL IRAQ
Authors: Sadooni F. N. 
Published: March 2006

Middle Turonian ‐ lower Companion carbonates in central Iraq contain estimated cumulative reserves of around 9 billion brl. More than 90% of this oil is in the Turonian Khasib Formation which forms an important reservoir at the giant East Baghdad and Balad oilfields and also at a number of other fields in central and southern Iraq. Minor volumes of oil are present in the overlying Tanuma and Sa'di Formations.The Khasib Formation consists of limestones and marlstones containing planktonic foraminifera and calcispheres together with extensively bioturbated chalks. These sediments were laid down in a basimal to sub‐basinal setting which evolved into a shallow‐ marine shelf or coastal lagoon.The best porosity (around 20%) occurs in the intensively bioturbated middle part of the formation, in which chalky matrix porosity is enhanced by an extensive network of micro‐fractures. The Tithonian‐Berriasian Chia Gara and the Valanginian‐Campanian Balambo Formations are potential source rocks for this oil. Organic matter is mostly marine Type II kerogen or mixed marine‐continental.
GEOCHEMICAL CHARACTERISTICS OF OIL SEEPAGES FROM DAM THI NAI, CENTRAL VIETNAM: IMPLICATIONS FOR HYDROCARBON EXPLORATION IN THE OFFSHORE PHU KHANH BASIN
Authors: Bojesen‐Koefoed J. A. , Nielsen L. H. , Nytoft H. P. , Petersen H. I. , Dau Nguyen Thi , Hien LeVan , Duc Nguyen Anh , Quy Nguyen Huy 
Published: March 2006

Dam Thi Nai is a semi‐enclosed embayment on the coast of central Vietnam, adjacent to the northern part of the offshore and largely unexplored Phu Khanh Basin. Seepages of oil have been known in Dam Thi Nai since the early part of the twentieth century. This paper presents organic geochemical data on a number of samples of seepage oil collected from Dam Thi Nai and discusses their implications for the prospectivity of the Phu Khanh Basin. The results indicate that the petroleum was generated from a Tertiary marine marl source rock.Seepage oils are found in varying degrees of biodegradation and modes of occurrence at different locations in the embayment. Thus, oil was observed to fill fractures in freshly quarried outcrops of Cretaceous granite, and also occurs in shallow pits dug in the beach sand and in shallow basins used for shrimp farming. The oils indicate active seepage from kitchen areas or leaking accumulations in the Phu Khanh Basin. Seismic data suggest the existence of both source rocks and kitchens, and indicate a possible migration route from the deep basin to the surface at the bay. A few samples show anomalous compositions, indicating the presence of two other oil types which have different sources. These occurrences cannot at present be explained. However, the results obtained are encouraging for future exploration in the Phu Khanh Basin.
ORIGIN AND RESERVOIR ROCK CHARACTERISTICS OF DOLOSTONES IN THE EARLY TRIASSIC FEIXIANGUAN FORMATION, NE SICHUAN BASIN, CHINA: SIGNIFICANCE FOR FUTURE GAS EXPLORATION
Authors: Zhao Wenzhi , Luo Ping , Chen Gengsheng , Cao Hong , Zhang Baoming 
Published: March 2006

Major discoveries of natural gas have recently been made in the oolitic dolostones of the Early Triassic Feixianguan Formation in NE Sichuan Province, Southern China. These dolostones were formed by three facies‐controlled dolomitization processes: (i) meteoric mixing zone dolomitization with dolomites having a relatively high degree of crystalline order (δ13C:−1.0 to 2.5%PDB; δ18O:−6.5 to −2.5%PDB); (ii) seepage‐reflux dolomitization associated with evaporative brines; the corresponding dolomite crystals are relatively ordered and were formed in tidal flat environments and platform‐margin oolitic shoals adjacent to lagoons; (iii) burial dolomitization (shallow to moderate burial depths, ca. 1,000 to 4,000m), whereby seawater‐derived brines were present in the host rock and the resultant water/rock reactions played a major role in dolomitization.The three dolomitization processes were controlled by the arid climate prevailing during the Early Triassic, and also by fourth‐order relative sea‐level changes, especially with respect to the reflux dolomitization. Burial dolomitization, which is of second‐order of importance for porosity development, was strongly dependant on the presence of sufficient original porosity to facilitate water‐rock reactions within the carbonates. The best reservoir rocks formed as oolitic banks and bars in the vicinity of evaporative lagoonal‐tidal complexes which experienced optimal conditions for dolomitization. Dolostones with a dolomite content of 80% to 90% form good vuggy reservoir rocks at the present day, indicating that the intensity of dolomitization influences the quality of reservoir rocks.According to our results, future gas exploration in the Feixianguan Formation dolostone reservoirs should focus on locating oolitic banks associated with evaporative lagoon and tidal flat complexes and delineating the best structural/lithological traps.
A METHOD FOR ANALYZING GEOTHERMAL GRADIENT HISTORIES USING THE STATISTICAL ASSESSMENT OF UNCERTAINTIES IN MATURITY MODELS
Authors: Huvaz O. , Thomsen R. O. , Noeth S. 
Published: March 2006

A major factor contributing to uncertainty in basin modelling is the determination of the parameters necessary to reconstruct the basin's thermal history. Thermal maturity modelling is widely used in basin modelling for assessing the exploration risk. Of the available models, the chemical kinetic model Easy%Ro has gained wide acceptance.In this study, the thermal gradient at five wells in the Danish North Sea is calibrated against vitrinite reflectance using the Easy%Ro model coupled with an inverse scheme in order to perform sensitivity analysis and to assess the uncertainty. The mean squared residual (MSR) is used as a quantitative measure of mismatch between the modelled and measured reflectance values. A 90% confidence interval is constructed for the determined mean of the squared residuals to assess the uncertainty for the given level of confidence. The sensitivity of the Easy%Ro model to variations in the thermal gradient is investigated using the uncertainty associated with scatter in the calibration data. The best thermal gradient (minimum MSR) is obtained from the MSR curve for each well. The aim is to show how the reconstruction of the thermal gradient is related to the control data and the applied model.The applied method helps not only to determine the average thermal gradient history of a basin, but also helps to investigate the quality of the calibration data and provides a quick assessment of the uncertainty and sensitivity of any parameter in a forward deterministic model.