bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ground Water Beneath Coastal Bays of the Delmarva Peninsula: Ages and Nutrients
Authors: Bratton John F. , Böhlke John Karl , Manheim Frank T. , Krantz David E. 
Published: March 2006

AbstractTo complement a large‐scale geophysical investigation of occurrence and discharge of fresh water beneath Delaware, Maryland, and Virginia (Delmarva) coastal bays, we measured (1) salinity and nutrient concentrations in ground water samples from several offshore coring sites and (2) a suite of chemical and isotopic parameters, including age tracers, in ground water samples from a Delaware site. Samples were collected in a variety of Holocene and Plio‐Pleistocene sediments in nearshore and offshore areas of the bays. Ground waters that were significantly fresher than overlying waters were found in plumes up to at least 15 m thick extending to more than 500 m offshore in some areas. Steep salinity and nutrient gradients occur within a few meters of the sediment surface in most locations studied. The zone of transition from deeper fresher waters to shallower brackish waters is generally thin near shore, but thickens and becomes more gradual offshore. Ground water ages at the Delaware site were mostly < 50 yr in both fresh waters and brackish waters up to 22 m below the bay bottom. Water chemistry and age data indicate that fresh water plumes beneath the estuary are active extensions of the surficial aquifer carrying nitrate from recharge areas on land, whereas brackish ground water surrounding the fresh water plumes is recharged beneath the estuary and contains ammonium and phosphate released by diagenesis of shallow estuarine sediments. Denitrification affects some of the fresh water nitrate before it mixes with brackish ground water or discharges to surface water.
Septic Tank Impacts on Ground Water Quality and Nearshore Sediment Nutrient Flux
Authors: Reay William G. 
Published: March 2006

AbstractField studies were conducted at three coastal plain sites to characterize inorganic nutrient and fecal coliform bacteria ground water quality and intertidal sediment nutrient fluxes under the influence of residential septic tank effluent. Mean drainfield DIP (dissolved inorganic phosphorus) and DIN (dissolved inorganic nitrogen) concentrations varied between 294 to 336 and 4494 to 5391 μmol/L, respectively, with mean fecal coliform bacteria densities ranging from 105.04 to 106.29 MPN (most probable number) /100 mL. DIP and fecal coliform bacteria exhibited a high degree of attenuation with shoreline concentrations at or near background levels. In contrast, septic tank nitrogen loadings to shallow ground water were significant and resulted in mean shoreline DIN concentrations ∼50 to 100 times greater than adjacent surface water concentrations. Mean site sediment DIP and DIN flux to surface waters varied from 1.1 to 1.6 and 52 to 135 μmol/m2/hr, respectively. Whereas DIP sediment fluxes were similar to reported values for sites adjacent to forested and agricultural lands, DIN fluxes were elevated compared to forested lands and near the lower end of the range reported for agricultural lands within the southern Chesapeake Bay region. Maximum measured sediment DIN flux was 1514 μmol/m2/hr. Estimated waste water nitrogen loading to shallow ground water (5.7 to 10.7 kg/household/yr) was significant and with 0.5 to 1 acre lot sizes, comparable to water table nitrogen loadings from dominant row‐crop land use in the mid‐Atlantic Coastal Plain. Given the trends in population growth in the Chesapeake Bay watershed and other coastal regions, nitrogen loads from septic tanks to these systems should also be expected to increase.
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.
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.
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.
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.