bluuebunny/crossref_metadata_2025 huggingface dataset:
SOLUTION SEAMS IN THE MAMUNIYAT FORMATION, EL‐SHARARA‐A FIELD, SW LIBYA: IMPACT ON RESERVOIR PERFORMANCE
Authors: Mohammed K. , Corbett P. W. M. , Bowen D. , Gardiner A. R. , Buckman J.
Published: March 2006

Solution seams have been identified as a significant component in the Ashgillian (Upper Ordovician) Mamuniyat Formation sandstone reservoir in the El‐Sharara‐A field (SW Libya). They have been observed in cores with a frequency of up to 25 solution seams per metre, and they have a permeability of 1–6mD in a reservoir whose permeability is otherwise 100–1,000mD. The reservoir sandstones (quartz arenites) were deposited as shallow‐marine shoreline sands associated with glacial outwash deposits. The potential of solution seams to act as permeability baffles has not previously been considered in reservoir engineering models of this field. In this study, by measurement of permeability and subsequent reservoir simulation, we show that solution seams are likely to have had a negligible effect on effective horizontal permeability, and a small but positive effect on vertical sweep efficiency (due to reduced vertical permeability). Solution seams are present in many Palaeozoic reservoirs in North Africa, and may be particularly significant (in terms of their effect on production) in relatively poor quality reservoirs.
GEOCHEMICAL CHARACTERIZATION OF CENOMANIAN/TURONIAN BLACK SHALES FROM THE TARFAYA BASIN (SW MOROCCO)
Authors: Kolonic S. , Sinninghe Damsté J. S. , Böttcher M. E. , Kuypers M. M. M. , Kuhnt W , Beckmann B. , Scheeder G. , Wagner T.
Published: March 2006

Organic geochemical and petrological investigations were carried out on Cenomanian/Turonian black shales from three sample sites in the Tarfaya Basin (SW Morocco) to characterize the sedimentary organic matter. These black shales have a variable bulk and molecular geochemical composition reflecting changes in the quantity and quality of the organic matter. High TOC contents (up to 18wt%) and hydrogen indices between 400 and 800 (mgHC/gTOC) indicate hydrogen‐rich organic matter (Type I‐II kerogen) which qualifies these laminated black shale sequences as excellent oil‐prone source rocks. Low Tmax values obtained from Rock‐Eval pyrolysis (404–425 MC) confirm an immature to early mature level of thermal maturation.

Organic petrological studies indicate that the kerogen is almost entirely composed of bituminite particles. These unstructured organic aggregates were most probably formed by intensive restructuring of labile biopolymers (lipids and/or carbohydrates), with the incorporation of sulphur into the kerogen during early diagenesis. Total lipid analyses performed after desulphurization of the total extract shows that the biomarkers mostly comprise short‐chain n‐alkanes (C16–C22) and long‐chain (C25–C35) n‐alkanes with no obvious odd‐over‐even predominance, together with steranes, hopanoids and acyclic isoprenoids. The presence of isorenieratane derivatives originating from green sulphur bacteria indicates that dissolved sulphide had reached the photic zone at shallow water depths (∼100m) during times of deposition. These conditions probably favoured intensive sulphurization of the organic matter. Flash pyrolysis GC‐MS analysis of the kerogen indicates the aliphatic nature of the bulk organic carbon. The vast majority of pyrolysis products are sulphur‐containing components such as alkylthiophenes, alkenylthiophenes and alkybenzothiophenes. Abundant sulphurization of the Tarfaya Basin kerogen resulted from excess sulphide and metabolizable organic matter combined with a limited availability of iron during early diagenesis. The observed variability in the intensity of OM sulphurization may be attributed to sea level‐driven fluctuations in the palaeoenvironment during sedimentation.
ORGANIC FACIES OF EARLY CRETACEOUS SYNRIFT LACUSTRINE SOURCE ROCKS FROM THE MUGLAD BASIN, SUDAN
Authors: Mustafa A. A. , Tyson R. V.
Published: March 2006

Cuttings samples from eight wells in the Muglad Basin have been analysed using a combination of organic geochemistry and palynofacies. The lacustrine Aptian‐Albian shales of the Abu Gabra Formation, previously identified as the main source rock, have an overall mean TOC of 1.43% (n = 146), with those from the NW part of the basin (Sharaf area) being approximately twice as organic‐rich as those from the SE (Heglig area). The Abu Gabra Formation contains two distinct organic facies: a lower interval dominated by higher TOC values (1.5–2.3%), higher measured hydrogen indices (338–546), higher amorphous kerogen contents (>80%), and heavier δ13CTOC values (> −27%0); and an upper, less rich interval (mean TOC 1.4%, mean HI 83, δ13CTOC approximately −28%0). The isotopic contrast between the upper and lower units may potentially be of stratigraphic use. The organic facies differences appear to reflect deteriorating preservation of the organic matter (higher dissolved oxygen, possibly due to shallower conditions resulting from lower rates of subsidence). Use of S2 v. TOC plots suggests corrected true mean hydrogen indices of around 800 in the richer facies (corresponding to a Type I kerogen). Mean random vitrinite reflectance, pyrolysis Tmax values, and visually determined fluorescence colours indicate that the samples studied are mostly immature, or at most in the earliest part of the oil window (<0.7% VRo); biomarker data suggest that the vitrinite reflectance values may be suppressed by up to 20%.
THE IMPACT OF DATA INTEGRATION ON GEOSTATISTICAL POROSITY MODELLING: A CASE STUDY FROM THE BERRI FIELD, SAUDI ARABIA
Authors: Al‐Khalifah M. , Makkawi M.
Published: March 2006

Understanding the spatial distribution of reservoir properties such as lithology and porosity is essential for development drilling, reserves estimation and fluid flow simulation. However, the data typically come from various sources at various scales and have varying degrees of reliability. Data such as wells logs and cores on their own are generally not adequate to produce an accurate model of a reservoir. Geostatistics provides a means for geologists and engineers to analyze this data, and to transfer the resulting analyses and interpretations for the purpose of reservoir modelling and forecasting.

The objective of this paper is to assess the added value that is gained by integrating different types of data (such as depositional facies and seismic impedance) with 3‐D geostatistical porosity models. To achieve this goal, four porosity models of the Hanifa Reservoir at the Berri field (Saudi Arabia) were built using different geostatistical modelling algorithms. The first porosity model was based solely on porosity logs from wells. The other three porosity models were generated using different combinations of porosity logs, depositional facies and seismic impedance data. These models were evaluated qualitatively and quantitatively.

The results of this study show that facies‐based porosity models result in the better definition of porosity both vertically and laterally compared to the other models. The seismic‐controlled model was the most precise—seismic data has a greater sample density than well data. Porosity from the wells‐only model has the lowest accuracy compared to the other models, which shows the importance of introducing other types of data in porosity modelling.

It is concluded that the utilization of different data sources has a pronounced positive impact when modelling areas with low sampling density. Integrating seismic impedance and facies data in porosity modeling improves the overall model accuracy and generates more reliable images about reservoir heterogeneity.
TEMPERATURE AND BURIAL HISTORY MODELLING OF THE DRMNO AND MARKOVAC DEPRESSIONS, SE PANNONIAN BASIN, SERBIA
Authors: Ercegovac M. , Kostic A. , Karg H. , Welte D. H. , Littke R.
Published: March 2006

We have modelled the subsidence, thermal and maturation history of the Drmno and Markovac depressions in the SE Pannonian Basin (Serbia) in order to calculate quantities of generated, expelled and migrated hydrocarbons. Stratigraphic, lithofacies, structural, thermal and geochemical data were used to create a conceptual model of the basin's evolution to depths of 5,000m. The models were calibrated using present‐day temperature and vitrinite reflectance data from representative wells. The results show that in the centres of these depressions, possible Badenian and pre‐Badenian (i.e. Middle and Lower Miocene) source rocks are sufficiently mature to have generated oil and gas.

Maturity data reveal significant differences in heat flow during times when maximum palaeotemperatures were reached. From these data high heat flows can only be deduced for some of the wells, whereas similar high heat flows are deduced from present‐day temperature data. Future research is necessary to resolve in detail the geologic evolution of the study area which resulted in the significant differences between the Mio/Pliocene and Recent heat flows.

Petroleum generation is taking place at depths below 2,000m in both depressions, mainly from Pre‐Badenian source rocks which contain Type II‐III kerogen and which appear to have a high petroleum generation potential.
GEOLOGICAL INTERPRETATION OF WELL TEST ANALYSIS: A CASE STUDY FROM A FLUVIAL RESERVOIR IN THE GULF OF THAILAND
Authors: Zheng S. Y. , Corbett P. W. M. , Emery A.
Published: March 2006

One problem with the inversion of transient well test data is that it can yield a non‐unique solution. The uncertainty resulting from this type of approach can only be resolved by considering information from another source such as geology. Geological information will help to define the interpretation model which will ensure the correct analysis of the well test data. The results of well test analyses are of little value to reservoir characterisation and modelling unless they can be explained from a geological point of view. This last step is what we refer to here as geological interpretation. Other sources of information which can help with well test analyses come from seismic surveys and petrophysics. Modern well test interpretation therefore consists of two major steps: analysis of the well test data; and interpretation of the results. In detail, this should include the following:

definition of an interpretation model — this requires the integration of geological, seismic and petrophysical data with transient pressure data

analysis of the well test data based on the interpretation model defined

geological interpretation of the results, which is necessary in order to explain or give meaning to the results.

In this paper, we present a case study from a fluvial gas reservoir in the Gulf of Thailand which demonstrates these procedures. In the context of a defined geological environment, a transient pressure test has been fully analysed. Newly‐developed software based on the finite element method has been used to forward model the test scenarios. This allowed the results of seismic and petrophysical analyses to be integrated into the well test model.

This case study illustrates the integrated use of geological, petrophysical, well test and seismic attribute data in defining a reservoir model which respects both the reservoir geometry at some distance from the well location and also the reservoir's heterogeneity. We focus on a particular well in the Pattani Basin at which conventional well test analyses have been conducted. By considering the results of these analyses, forward modelling was carried out in which the drainage area was “cut” out of the structural map defined by seismic interpretation; also, the formation's internal heterogeneity was modelled according to well logs and petrophysical analyses. Finally, analytical and simulation results were compared with the transient pressure data.

We conclude that the integration of geological, seismic, petrophysical and well test data greatly reduced uncertainties in well test interpretation. The consistency of the results and the fact that they satisfied all the relevant disciplines meant that much more confidence could be given to their interpretation.
GEOCHEMICAL CORRELATION OF CRUDE OILS IN THE NW NIGER DELTA, NIGERIA
Authors: Eneogwe C. , Ekundayo O.
Published: March 2006

Sixty‐six oils from eleven offshore and onshore fields in the NW Niger Delta, Nigeria were analyzed geochemically for their biomarker and isotopic compositions. Multivariate statistical analysis was employed to distinguish generic oil families from the large, complex data set. Biomarker and isotopic source parameter distributions were used to group the oils into three generic families. Family A oils, located in the onshore swamp to transitional area, received charges from predominantly Late Cretaceous or younger marine source rocks laid down in a sub‐oxic to oxic depositional environment. Family B oils occur in the near‐offshore area and are derived from Tertiary source facies that received an input of mixed terrigenous and marine organic matter. Family C oils, which dominate the offshore area, were derived from Tertiary source rocks typical of those deposited in oxic, nearshore or deltaic settings receiving significant terrestrial organic matter. Biomarker maturity parameters showed that the onshore (swamp) oils were generated at the peak of the oil generating window, while the transitional to offshore oils were expelled at an earlier stage of oil generation.
URANIUM SPECTRAL GAMMA‐RAY RESPONSE AS A PROXY FOR ORGANIC RICHNESS IN BLACK SHALES: APPLICABILITY AND LIMITATIONS
Authors: Lüning S. , Kolonic S.
Published: March 2006

In many organic‐rich, low‐carbonate hemipelagic shales, there is a stable and close correlation between the uranium and TOC contents. In this paper, we present a number of case studies using our own data and that from previous publications to investigate black shales with (1) good, (2) fair‐to‐good and (3) poor U/TOC correlations. U/TOC ratios in the different black shale units are compared to each other, and possible reasons for the observed variations are discussed.

In general, the U/TOC ratio in a black shale is controlled by a number of factors which include for example the primary uranium content of the water body, the carbonate content and the sedimentation rate. The development of a stable U/TOC ratio may be inhibited by the presence of phosphate, by a high carbonate or sand content, by dissolution (“burn‐down”) of uranium during intermittent oxic periods, and by large‐scale diagenetic remobilisation of uranium. In suitable black shale systems, vertical variations in organic richness can be approximated by measuring the uranium content using spectral gamma‐ray measurements. This may be especially important in outcrop studies because gamma‐ray logging is a straightforward field technique. Before the uranium content can be used as a proxy for TOC content in a black shale system, however, a thorough calibration of uranium and TOC is necessary, in order to determine the stratigraphic and regional limits of the derived U/TOC ratios and to establish the presence of a stable U/TOC correlation.
THE RESERVOIR POTENTIAL OF MIOCENE CARBONATE ROCKS IN THE ASKALE AND HINIS‐MUS‐VAN SUB‐BASINS, EAST ANATOLIA, TURKEY
Authors: Büyükutku A. G.
Published: March 2006

Lower‐middle Miocene limestones in East Anatolia (eastern Turkey) assigned to the Adilcevaz Formation were studied using core and cuttings data from eight wells in the Tertiary Askale and Hinis‐Mus‐Van sub‐basins. Their depositional environment, diagenetic characteristics and reservoir quality are reviewed.

The Adilcevaz Formation carbonates are up to 225m thick. Abundant bioclasts are dominated by corals, encrusting red algae, bryozoans, and benthonic and planktonic foraminifera. Reef‐core, fore‐reef and back‐reef facies were recognized. The preservation of primary porosity is generally poor as a result of late calcite cementation. Porosity is mainly present as moulds, vugs and interparticle types, which are best developed in the fore‐reef and reef‐core facies. However these pores are poorly connected and permeability is generally less than 0.1 mD. In contrast to coeval limestones of similiar facies in Iran, Iraq and other parts of the Middle East, the Adilcevaz Formation has little reservoir potential.
HYDROCARBON SEEPAGE GENERATION AND MIGRATION IN THE SOUTHERN GULF OF SUEZ, EGYPT: INSIGHTS FROM BIOMARKER CHARACTERISTICS AND SOURCE ROCK MODELLING
Authors: Younes M. A.
Published: March 2006

Active oil seepages in the Gebel El‐Zeit area (southern Gulf of Suez, Egypt) occur in fault zones on the western flank of the East Zeit Basin. Gas chromatography‐mass spectrometry indicates that these oils are rich in tricyclic terpanes and extended hopanes with few diasteranes. These characteristics are typical of oils derived from marine siliciclastic source rocks; an input of terrestrial angiosperms material is indicated by the very high oleanane index of 32.65% and the low gammacerane index of 6.28%. The molecular maturity parameter C29ααα cholestane [20S/(20S+20R)] is < 0.5 indicating that these oils were generated at relatively low thermal maturities. The seepage oils resemble Miocene crude oils in the East Zeit Basin which are believed to be generated from the Lower Miocene Rudeis Shale. Burial history modelling indicates that oil generation from this unit began at around 3–4 Ma at vitrinite reflectance levels of Ro%=0.60–0.85. This implies extensive lateral and vertical migration has taken place for the generated oil to reach the surface. Alternatively, the seepage oils may be sourced by leakage from preexisting accumulations.
UNCONVENTIONAL OIL ACCUMULATIONS IN THE UPPER JURASSIC BAZHENOV BLACK SHALE FORMATION, WEST SIBERIAN BASIN: A SELF‐SOURCED RESERVOIR SYSTEM
Authors: Lopatin N. V. , Zubairaev S. L. , Kos I. M. , Emets T. P. , Romanov E. A. , Malchikhina O. V.
Published: March 2006

The Upper Jurassic Bazhenov Formation in the central West Siberian Basin is a classic marine black shale unit containing abundant Type II kerogen with high oil‐generation potential. These shales source around 90% of the oil in the West Siberian Basin. They also contain oil accumulations in unconventional self‐sourced reservoirs. Reservoir zones are generally small and are located along fault planes. Primary oil migration was focused along fracture networks adjacent to the fault zones. Oil charging took place in the Tertiary and oil generation and expulsion in the Bazhenov Formation led to overpressuring. In the study area between the Surgut and Nyalinsk arches in the centre of the basin, faulting and fracturing took place in Eocene to Quaternary time. The faulting led to local increases in the thermal maturity of the Bazhenov Formation. Exploration risk in the self‐sourced Bazhenov Formation reservoirs mainly relates to seismically‐defined regional faults or to transverse faults.
CONTROLS ON THE DISTRIBUTION OF NUMMULITE FACIES: A CASE STUDY FROM THE LATE YPRESIAN EL GARIA FORMATION (KESRA PLATEAU, CENTRAL TUNISIA)
Authors: Jorry S. , Davaud E. , Caline B.
Published: March 2006

Eocene nummulite deposits along the southern Tethys margin locally constitute important hydrocarbon reservoir rocks. In order to understand the heterogeneity of these complex reservoirs, we have carried out a detailed field study of the nummulite limestones which crop out at the Kesra Plateau in Central Tunisia. The main contributions of this paper can be summarised as follows:

Various species of Nummulites and planktonic foraminifera were identified in late Ypresian carbonates in the Kesra area and provided accurate biostratigraphic ages. Nummulitic limestones occur in the Chouabine and El Garia Formations representing deposition over a period of about 2Ma.

Six depositional facies have been identified in the El Garia Formation, ranging from high‐energy nummulitic grainstones to laterally‐equivalent lower‐energy nummulithoclastic accumulations. Variations in nummulite morphology (size and shape) were used to distinguish a number of subfacies which correspond to different depositional environments. We provide evidence that nummulite accumulations were locally sub‐aerially exposed.

A 3D reconstruction of the Kesra Plateau outcrop identified two stacked nummulite bodies, deposited under high‐energy conditions, which pass laterally into two isolated bodies in more distal parts of the platform.

Regional‐scale observations indicate that the geometry of the late Ypresian nummulite platform was strongly influenced by the presence of the Oued Bahloul anticline structure, which formed a major environmental barrier between open‐marine and more restricted settings. Facies distribution in the Kesra area was strongly controlled by the inherited topography, which reflects the reactivation of NW‐SE trending faults during the Late Cretaceous and Paleocene.

A tentative 3D facies model illustrates the relationship between facies and fault distributions in the Kesra area. The facies map shows that the best reservoir potential is associated with palaeo‐highs, and consists of nummulite limestones deposited in very shallow waters (a few metres) under high‐energy conditions.
HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINA
Authors: Ding A. N. , Hui R. Y. , Zhang Z. N.
Published: March 2006

Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon‐generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher‐plant origin. In lacustrine facies, macerals consists of bacterially‐altered amorphinite, algal‐ amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin.

The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source‐rock maturation, an “early” stage and a “mature” stage. Ro values are 0.4%–0.7% in the former and 0.8%–1.2% in the latter.
ORDOVICIAN—PERMIAN PALAEOGEOGRAPHY OF CENTRAL EURASIA: DEVELOPMENT OF PALAEOZOIC PETROLEUM‐BEARING BASINS
Authors: Bykadorov V. A. , Bush V. A. , Fedorenko O. A. , Filippova I. B. , Miletenko N. V. , Puchkov V. N. , Smirnov A. V. , Uzhkenov B. S. , Volozh Y. A.
Published: March 2006

In this paper, we discuss three petroleum‐bearing basins of Palaeozoic age in Central Eurasia—the Precaspian, Tarim and Chu‐Sarysu Basins. We make use of recently‐published palaeogeographic maps of the Central Eurasian region, six of which are presented here (Late Ordovician, Early‐Middle Devonian, Late Devonian, Early Carboniferous, Early Permian and Late Permian). The maps illustrate the development through the Palaeozoic of the Palaeoasian and Palaeotethys Oceans; of the East European, Siberian and Tarim cratons; and of the Kazakhstan and other microcontinental blocks.

The Kazakhstan block formed during the Late Ordovician and is a collage of Precambrian and Early Palaeozoic microcontinents and island arcs. It is surrounded by collisional foldbelts (Ob‐Zaisan, Ural‐Tianshan and Junggar‐Balkhash) which formed in the Late Carboniferous — Permian. We believe that the formation of a stable Kazakhstan block is not consistent with the existence of the previously‐identified “Kipchak arc” within the Palaeoasian ocean, or (as has previously been proposed) with activity on this arc up to the end of the Palaeozoic.

The oil and gas potential of the Precaspian, Tarim and Chu‐Sarysu Basins depends to a large extent on their tectonic stability during the Palaeozoic and subsequent time. The Precaspian Basin has been stable since the Cadomian orogeny (Early Cambrian) and is known to have major hydrocarbon potential. The Tarim Basin (NW China) has somewhat lower potential because the margins of the Tarim continental block have been affected by a series of collisional events; that margin with the Palaeotethys Ocean, for example, was active during the Late Palaeozoic. The Chu‐Sarysu Basin on the Kazakhstan block is the least stable of the three and contains only minor gas accumulations.
UPPER TRIASSIC‐MIDDLE JURASSIC STRATIGRAPHY AND SEDIMENTOLOGY IN THE NE QAIDAM BASIN, NW CHINA: PETROLEUM GEOLOGICAL SIGNIFICANCE OF NEW OUTCROP AND SUBSURFACE DATA
Authors: Yongtai Yang , Ritts B. , Caineng Zou , Tianguang Xu , Baomin Zhang , Ping Xi
Published: March 2006

Although Mesozoic source and reservoir rocks are known to occur at oilfields in the northern Qaidam Basin (NW China), the precise identification and distribution of Mesozoic rocks in the subsurface are outstanding problems. The Dameigou locality has in the past been considered as the type section for Lower‐Middle Jurassic strata in northern Qaidam. Previous studies have concluded that the onset of non‐marine sedimentation here took place in the Early Jurassic; and that Mesozoic strata penetrated by wells in the Lenghu structural zone are Middle Jurassic.

In this paper, we present new data from the Lengke‐1 well, drilled in the Lenghu structural zone in 1997. This data indicates the existence of a more extensive pre‐Middle Jurassic stratigraphy than has previously been recognized. Biostratigraphic data together with regional seismic mapping suggest that the pre‐Middle Jurassic succession at Lengke‐1 includes both Late Triassic and Early Jurassic deposits. The Late Triassic sedimentary rocks appear to have been deposited in local half graben, some of which were later inverted during Jurassic, Cretaceous and Cenozoic tectonism.

Lower and Middle Jurassic strata (lacustrine and fluvial deposits) are present in the SW and NE parts of the Lenghu structural zone, respectively. Extensive organic‐rich intervals are present in both successions. Lower Jurassic lacustrine mudstones may represent a previously under‐appreciated, and potentially large, source rock sequence.
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.
THE DISTRIBUTION OF LIGHT HYDROCARBONS IN WESTERN NIGER DELTA OILS
Authors: Eneogwe C. I.
Published: March 2006

Fifty‐one oils from ten fields in the Western Niger Delta were analyzed for their C7 hydrocarbon contents. Hierarchical Cluster Analysis and Principal Component Analysis were used to discriminate the oils into four sets which were distinct in all the seven variables used in the cluster analysis. Methylcyclohexane and toluene were the most important discriminating variables. In spite of this separation into four sets, all the oils were found to exhibit a high six‐ring preference (6RP). The distribution of C7 hydrocarbons in the oils indicated that two of the eleven fields are homogenous in terms of oil type, whereas the rest are not.
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.
NMR ANALYSIS OF AMBER IN THE ZUBAIR FORMATION, KHAFJI OILFIELD (SAUDI ARABIA – KUWAIT): COAL AS AN OIL SOURCE ROCK?
Authors: Poinar George , Lambert Joseph B. , Wu Yuyang
Published: March 2006

Amber samples obtained from coal deposits in the Zubair Formation at a depth of 1,800 m from the offshore Khafji oilfield (Saudi Arabia ‐ Kuwait Partitioned Neutral Zone) were subjected to NMR analysis. The resulting spectra identified the samples as originating from trees belonging to the genus Agathis. The NMR spectra were virtually identical to those obtained from Lower Cretaceous amber from Lebanon, Israel and Jordan, suggesting that a large forest of Agathis levantensis extended across the Arabian Plateau from the Levant to the Gulf. In this case, the forest would have extended a distance of approximately 1500 km, which would make it the largest amber‐producing forest known. It is suggested that the oil in the Khafji and adjoining Safaniya oilfields could have been derived from coal produced, at least in part, by Agathis levantensis.
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.
ASPECTS OF THE PETROLEUM GEOLOGY OF THE BERMEJO FIELD, NORTHWESTERN ORIENTE BASIN, ECUADOR
Authors: Lee G. H. , Eissa M. A. , Decker C. L. , Castagna J. P. , O'Meara D. J. , Marín H. D.
Published: March 2006

The principal reservoirs in the Bermejo oilfield in the NW Oriente Basin of Ecuador are the Cretaceous Hollin Formation and the basal sandstone in the Tena Formation (“basal Tena sand”). Analysis of 3D seismic and wireline log data suggests that much of the Hollin Formation consists of stacked fluvial channel deposits. In the overlying Napo Formation, the excellent correlation of log signatures, continuous seismic reflections, and the absence of thick sandstone layers (except for the coarsening‐upward Napo “T” sand), suggest deposition from uniform processes, possibly in a shelf environment. The upper Napo and lower Tena Formations are interpreted as a series of transgressive deposits, punctuated by the basal Tena sand. Truncation in the Hollín Formation is better observed on east‐west seismic lines than on north‐south seismic lines, suggesting a north‐south trending fluvial system. This, together with the northward thinning of the top Hollín shale suggesting an east‐west trending palaeo‐shorezone, further predicts north‐south oriented reservoir distribution. The palaeogeography of the Oriente Basin was probably more complex than that portrayed in previous depositional models which depict a north‐south oriented palaeo‐shorezone and sediment supply from the east. Detailed depth structure maps reveal structural closures that have not been tested.
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.