bluuebunny/crossref_metadata_2025 huggingface dataset:
Long-term recovery in the soil profile of 15N from Douglas-fir needles decomposing in the forest floor
Authors: Preston CM. , Mead D.J.
Published: October 2008

To follow the movement and transformations of litter-fall N in a forest ecosystem, Douglas-fir (Pseudotsugamenziesii (Mirb.) Franco) foliage labelled with 15N was mixed into the forest floor and left to decompose in steel cylinders of 15 cm diameter X 60 cm length. There were four treatments: 15N-labelled foliage only, foliage plus 200 kg N•ha−1 as urea or NH4NO3, and unamended control. The addition of fertilizer N had no significant effects on 15N recovery or distribution in the soil profile. The overall recovery of 15N to 60 cm depth was 53.7%, 24.9%, and 19.9% after 1, 3, and 7.5 years, respectively. After the first year almost all of the recovered 15N was in the L layer. At 3 years, a higher proportion was found in the FH layer, and by 7.5 years, approximately one-third of the 15N was found in mineral soil horizons. There was very little recovery of 15N in inorganic form (1% or less) after 1 year; in subsequent years inorganic N was found at background levels. Recoveries in soil after 1 and 3 years were similar to those reported for 15N added as inorganic fertilizer in the absence of plant uptake. However, very low losses in the next sampling period (3 to 7.5 years) indicated stabilization of 15N in increasingly recalcitrant forms.
MEASUREMENT AND SIMULATION FOR WIND NOISES IN THE OCEAN ENVIRONMENTS WITH NONLINEAR INTERNAL WAVES
Authors: CHAN HSIANG-CHIH , WEI RUEY-CHANG , CHEN CHI-FANG
Published: October 2008

This study obtains wind noise variations by experimental data and simulated results to describe meteorological and oceanic effects. The ambient noise data were measured by a vertical line array in the 2001 ASIAEX South China Sea experiment. An acoustic propagation model is used in noise modeling for calculating the sound pressure of noises at receiving sites, including the effects of ocean environmental changes, bottom interactions, and noise fluctuations at different depths. Both range-independent and range-dependent sound speed profiles are generated with in-situ water temperature data. Results show fluctuating noise levels with variations in ocean environments. But the fluctuations are small such that only weak correlation exists in the acoustic noise data and ocean data. Results also indicate that using range-independent sound speed profiles can simulate noise field in range-dependent ocean environments with nonlinear internal waves for shallow regions with flat bottoms.
TWO-WAY COUPLED-MODE SOLUTIONS IN THE COMPLEX HORIZONTAL WAVENUMBER PLANE
Authors: STOTTS STEVEN A.
Published: October 2008

A coupled-mode formalism based on complex Airy layer mode solutions is presented. It is an extension into the complex horizontal wavenumber plane of the companion article [Stotts, J. Acoust. Soc. Am.111 (2002) 1623–1643], referred to here as the real horizontal wavenumber version, which accounted for general ocean environments but was restricted to normal modes on the real horizontal wavenumber axis. A formulation of the expressions for both trapped and continuum complex coupling coefficients is developed to dramatically reduce computer storage requirements and to make the calculation more practical. The motivation of this work is to demonstrate the numerical implementation of the derivations and to apply the method to an example benchmark. Differences from the real horizontal wavenumber formalism are highlighted. The coupled equations are solved using the Lanczos method [Knobles, J. Acoust. Soc. Am.96 (1994) 1741–1747]. Comparisons of the coupled-mode solution to a parabolic equation solution for the ONR shelf break benchmark validate the results.
Integrated Palaeogene palaeobathymetry of the northern North Sea
Authors: Kjennerud Tomas , Gillmore Gavin K.
Published: October 2008

This paper seeks to expand understanding by providing a wider and more integrated approach to the problem of palaeobathymetric reconstructions of the Palaeogene for the northern North Sea. This has been achieved by combining published and unpublished micropalaeontological studies from 12 wells between 58°N and 62°N, with regional reconstructed sections. These estimates were further integrated with regional seismic isopach maps to produce palaeobathymetric maps. The present results differ from previously published works in that they were integrated spatially, based on the type of regional depositional sequence they represent. The East Shetland Platform was uplifted and acted as a source area of sediment in the Palaeogene, with a palaeobathymetry of 800 m in the Viking Graben early in this period. During the Eocene, the deeper part of the generally N–S trending basin became narrower. A significant shallowing took place in the Oligocene, which was in part controlled by tectonic uplift of the basin.
Flow characterization of glauconitic sandstones by integrated Dynamic Neutron Radiography and image analysis of backscattered electron micrographs
Authors: Solymar Mikael , Fabricius Ida L. , Middleton Mike
Published: October 2008

The effects of porosity and pore geometry on the fluid saturation and immiscible displacement of greensand reservoir rocks were investigated on eight samples from the North Sea basin. Dynamic Neutron Radiography (DNR) was used to image the front stability during displacement experiments where oil was infiltrating water-saturated samples. The flow characteristics were related to petrography and pore geometry, which may be determined by image analysis of backscattered electron (BSE) micrographs. The fluid saturation observed in each DNR image was modelled in a corresponding BSE image as a means of evaluating the effect of pore geometry on front stability. Piston-like displacement and channelling were observed and these flow patterns were found to reflect variations in pore geometry. The samples with piston-like displacement have homogeneous pore space, whereas the samples with channelling have heterogeneous pore space, with spatial variations in porosity and pore size. The modelled saturation distribution was interpreted using results from petrographic and petrophysical analyses. The results suggest that the micropores of the glauconite grains and clay minerals contain water, whereas the oil is moving through the intergranular pore space during the displacement experiment.
A method for performing history matching of reservoir flow models using 4D seismic data
Authors: Lygren M. , Fagervik K. , Valen T.S. , Hetlelid A. , Berge G. , Dahl G.V. , Sønneland L. , Lie H.E. , Magnus I.
Published: October 2008

A generic method for performing history matching of reservoir flow models using 4D seismic data is described. Several key technology components are used in the procedure, including seismic attribute analysis and classification, reservoir simulator technologies, domain transformation algorithms, as well as the optimization algorithms that guide the history-matching process. The novel 4D history-matching procedure was applied to the Tordis Field in the North Sea. As a result the transmissibilities of the fault network in the reservoir model were modified. In addition a production well was successfully side-tracked using results of the analysis from the time-lapse data.
Analysis of time-lapse data from the Alba Field 4C/4D seismic survey
Authors: Hanson R. , Condon P. , Behrens R. , Groves S. , MacLeod M.
Published: October 2008

The 1998 Alba 3D Ocean Bottom Cable (OBC) survey was designed to accomplish multiple objectives. The primary goal was to image low impedance reservoir sands with converted wave (PS) reflections; one important secondary goal was to image fluid movement by comparing the OBC data with a 1989 streamer survey. Modelling shows that a strong original oil–water contact reflector should be visible throughout much of the field and that water saturation changes should be observable by analysing the time-lapse differences between the 1989 streamer data and 1998 OBC survey. Differences between the 1989 and 1998 seismic field data confirm that fluid changes are clearly visible near several producing and injector wells. However, extracting additional quantitative saturation information from the seismic data has proven difficult, possibly because of: (a) complex interaction between the fluids, sands and shales within the Alba reservoir; (b) moderate to poor repeatability of the seismic response to reservoir fluids.

The focus of this paper is the acquisition and analysis of Alba time-lapse data. We show that production- and injection-related effects are predicted by modelling and observed in the data and then we make an attempt to relate these effects quantitatively to oil production and water injection. Despite the challenges in using the Alba time-lapse data quantitatively, the data have been successfully used qualitatively for well planning risk assessment and for guiding reservoir simulation efforts. Lessons from this work will be used in any future time-lapse surveys at Alba.
Potential source rocks for the crude oils in the Ikizce and Tokaris oil fields, SE Turkey
Authors: Sari A. , Bahtiyar I. , Brenner R. L. , Dogan A. U.
Published: October 2008

The source rock and reservoir characteristics of the Upper Cretaceous‘ A’ Member of the Karababa Formation (Santonian–Coniacian) and the Karabogaz Formation (Campanian) and their relationships to the crude oils produced from the Ikizce and the Tokaris oil fields, were studied using a variety of organic geochemical methods. The Karabogaz Formation is composed of limestone and chert, while the Karababa-A Member consists of clayey limestones. Both formations constitute important source rocks in the Adiyaman Basin. The crude oils examined in this study were produced from reservoir rocks of the same age in two adjacent oil fields. Biomarker characteristics in source rock samples from the Ikizce-A and Tokaris-A wells show that the Karababa-A Member and the Karabogaz Formation were deposited in reducing environments and are characteristic of carbonate facies. Correlations between the source rocks and the crude oils, based on qualitative and quantitative biomarker distributions, indicate that the oils from the Ikizce and Tokaris fields are mixed oils that were derived from both the Karababa-A Member and the Karabogaz Formation source rocks.
Optimizing 4D fluid imaging
Authors: McInally A. T. , Redondo-López T. , Garnham J. , Kunka J. , Brooks A. D. , Stenstrup Hansen L. , Barclay F. , Davies D.
Published: October 2008

Integrated analysis of 4D seismic data and petrophysical data is used to produce probabilistic fluid and lithology volumes for monitoring reservoir performance on the Nelson Field. Petrophysical analysis of log data shows distinct fields for oil sand, water sand, shale and heterolithic‘ lithologies’ in acoustic impedance – Poisson's ratio space. Elastic inversion techniques applied to conventional 4D AVO datasets convert the reflectivity data to acoustic impedance, shear impedance, Poisson's ratio and angle impedances. The elastic inversion datasets are used to quantify oil–water contact movements through volume sculpting techniques. Well-derived relationships are used to predict 3D volumes of oil sand probability from three different seismic survey vintages: 1990, 1997 and 2000. Changes in oil sand probability due to production are verified by comparison with repeat production logs. Integrated volume interpretation of 4D far offset inversion difference (oil–water contact (OWC) movement) and oil sand probability shows areas of unswept oil, highlighting infill opportunities. Early results from infill drilling have validated the method, realizing the potential economic benefits of 4D seismic technologies.
Stratigraphic–structural interpretation and hydrocarbon potential of the Alaşehir Graben, western Turkey
Authors: Yilmaz M. , Gelisli K.
Published: October 2008

Two different graben sets were developed in western Anatolia (Turkey) under the influence of Neogene extension. NE–SW orientated grabens formed during the Miocene and provided suitable environments for the deposition of lacustrine bituminous shales and fan delta sediments. Younger E–W orientated grabens formed during the Pliocene and locally intersected the older NE–SW grabens. Such intersecting graben areas are characterized by superimposed graben fills. The Alaşehir Graben is an example of such a configuration within the E–W orientated Gediz Graben. The hydrocarbon potential and superimposed configuration of the Alaşehir Graben were examined using seismic, gravity and magnetic data. Seismic data were interpreted in an interactive interpretation system, using additional physical parameters generated by calculating instantaneous attributes on time-migrated seismic sections, aiding determinations of lithology and seismic facies. The Alaşehir Graben contains four sedimentary units developed under an extensional tectonic regime and is a superimposed graben containing possible traps as well as a high potential for hydrocarbon generation.
A method for correcting log-derived temperatures in deep wells, calibrated in the Gulf of Mexico
Authors: Waples Douglas W. , Pacheco Jorge , Vera Alfredo
Published: October 2008

A method for correcting log-derived temperatures in deep wells (3500–6500 m) has been developed by comparing log temperatures from the Gulf of Campeche (Mexican Gulf of Mexico) with DST temperatures in the same wells. The equations developed in this study are modified slightly from those of
Waples & Mahadir Ramly (2001)
, which were calibrated using data from depths <3500 m in Malaysia. The correction depends strongly on time since end of mud circulation (
TSC
) and, to a much lesser degree, on depth. In this study the true subsurface temperature (Celsius) is given by

\batchmode \documentclass[fleqn,10pt,legalpaper]{article} \usepackage{amssymb} \usepackage{amsfonts} \usepackage{amsmath} \pagestyle{empty} \begin{document} T_{true}=T_{surf}+f{\cdot}\left(T_{meas}{-}T_{surf}\right){-}0.001391\left(Z{-}4498\right)\end{document}

where
f
=1.32866

−0.005289
TSC

,
T
surf
is the seafloor or land-surface temperature (°C),
T
meas
is the measured log temperature (°C),
TSC
is in hours and
Z
is depth below seafloor in metres. If
TSC
is unknown, it can be estimated from the trend of
TSC
with depth.

An estimate of the uncertainty in the corrected temperature is obtained from the equation:

\batchmode \documentclass[fleqn,10pt,legalpaper]{article} \usepackage{amssymb} \usepackage{amsfonts} \usepackage{amsmath} \pagestyle{empty} \begin{document} {\sigma}=0.10842^{{-}0.029TSC}\end{document}

where
σ
is the standard deviation of the correction factor
f
. The uncertainty in the correction factor
f
can be expressed as ±2
σ
.
Anhydrite distribution within a shelf-margin carbonate reservoir:San Andres Formation, Vacuum Field, New Mexico, USA
Authors: Pranter Matthew J. , Hurley Neil F. , Davis Thomas L.
Published: October 2008

Anhydrite cement causes significant heterogeneity within the San Andres reservoir of the Vacuum Field where it is associated with faults, fractures, karst zones and highly cemented dolomite intervals. The primary reservoir rocks within the Central Vacuum Unit of the Vacuum Field are dolomitized peloidal packstones, skeletal and ooid grainstones and fusulinid packstones. These rocks alternate with lower reservoir-quality dolomite intervals with variable amounts of anhydrite cement. Nodular and pore-filling fabric-selective anhydrite cements are common within the reservoir interval. Cross-plots of apparent matrix grain-density versus apparent matrix volumetric cross-section (
ρ
maa
–
U
maa
cross-plots), combined with
V
p
/
V
s
seismic attributes and core data, provide insight into the vertical and lateral distribution of anhydrite within the San Andres reservoir. Anhydrite is generally concentrated in thin depositional cycles or intervals that are separated by relatively anhydrite-free cycles that exhibit relatively higher porosity and permeability. Lower
V
p
/
V
s
values correspond to higher percentages of anhydrite and are useful formapping anhydrite distribution. This evaluation of anhydrite distribution providesan estimate of the significant cementation-related heterogeneities within the reservoir that is useful for development-well planning and to target areas of bypassed pay.
Alwyn North Triassic Main gas-condensate: drilling deeper promotes production
Authors: Harker S. D. , Richardson G. , Sides L. E. , Cooper R.
Published: October 2008

Production of oil and gas in the Alwyn North Field, UKCS, commenced in 1987 from Middle Jurassic Brent and Lower Jurassic Statfjord reservoirs. In 1988, a deepened Statfjord producer well (3/9a-N21) detected gas in the underlying Triassic, but testing was not possible at that time. The 3/10b-2 exploration well, drilled in 1992 to the east of the field, tested gas at low rates from a poor quality Triassic reservoir section. In 1995 well 3/9a-N33, a deviated well, was drilled from the Alwyn platform to evaluate the productivity of the deep Triassic. This well penetrated 770 m of Upper Lunde section, which was tested at 1.3×10
6
m
3
per day of gas plus 4400 STB per day of condensate.

The Alwyn trap comprises a westerly dipping fault panel structure. Erosion over the crest of the tilted panel and the eastern-facing scarp slope by the Base Cretaceous Unconformity (BCU) truncates the Jurassic section down to the Upper Triassic. Sealing of the Triassic Main accumulation is by uppermost Triassic shales of the overlying Statfjord Formation and by Cretaceous mudrocks onlapping onto the BCU. Hydrocarbon charging of the Triassic Upper Lunde sandstones is from mature Late Jurassic Kimmeridge Clay source rocks that are juxtaposed against the reservoir along parts of the eastern frontal fault of the Alwyn panel.

The Upper Lunde (of Carnian to Rhaetian age) is a low net:gross reservoir section up to 800 m thick. The sediments are of semi-arid fluvial, floodplain and lacustrine origins, with the best reservoirs occurring in fluvial channel sandstones. The Late Triassic comprises four informal zones from A (top seal), through B and C to D reservoirs, above the Middle Lunde shale. The Triassic reservoir fluids are gas-condensate in the B and C units with an intraformational seal at the C–D boundary, beneath which lies volatile oil in the D unit.

A total of eight further Triassic production wells were added to the AlwynNorth Field by the end of 2001, as the development plan for Triassic Main progressed. These wells contribute in the order of 60% to the Alwyn North daily production.
Syn-sedimentary shear zones
Authors: Moretti I. , Calassou S. , Victor P. , Molinaro M. , Maerten L.
Published: October 2008

In deltaic and turbiditic deposits along passive margins, such as the Lower Congo basin on the West African margin, the main deformation is not induced by a regional tectonic stress field but by the increase of the sedimentary load leading to gravitational instabilities. The local stress field in such an environment is drastically influenced by the lithological discontinuities, which can reorientate the principal stresses induced by sedimentary loading. In this paper we document the localization of particular faults, called sedimentary shear zones (SSZ); these are formed along the borders of a sandy channel embedded in more fine-grained sediments, as a function of the lithological contrast. Furthermore we describe the reorientation of the stress field, perpendicular to the channel borders in the channel interior. Examples from 3D seismic lines and field studies in SW Ireland and Tunisia are compared with results from analogue and geomechanical models, leading to an integrated interpretation for the formation of the SSZ.
Geomechanical properties related to top seal leakage in the Carnarvon Basin, Northwest Shelf, Australia
Authors: Dewhurst David N. , Hennig Allison L.
Published: October 2008

The Muderong Shale is the regional top seal in the Carnarvon Basin on the Northwest Shelf of Australia. Evidence for top seal breach in this area comes from post-Muderong plays and hydrocarbon shows. Capillary pressure tests show this shale has the capability of restraining gas columns in excess of 250 m height, a value which is unlikely to be reached due to the intrinsic weakness of the Muderong Shale. Apart from one example, all hydrocarbon columns so far encountered in the Carnarvon Basin are well below this limit. Geomechanical testing of the Muderong Shale indicates it is a weak rock, commensurate with its high illite–smectite content. Comparison of laboratory-generated failure envelopes with in situ stress conditions suggest that intact Muderong Shale is not generally at risk of hydrofracture but that pre-existing faults and fractures may well be critically stressed in the present-day stress field. It is postulated that such faults and fractures may be responsible for top seal failure in the Muderong Shale and the resultant presence of hydrocarbons in the post-Muderong succession.
Multi-disciplinary study of the heavy-oil reservoirs in the Armatella Field, Sicily
Authors: Ruvo L. , Aldegheri A. , Galimberti R. , Nembrini E. , Rossi L. , Ruspi R.
Published: October 2008

The Armatella Field in SE Sicily is structurally complex with two fractured, carbonate reservoirs containing heavy-oils, with the heavier hydrocarbon overlying the lighter one. One well has been drilled in the field – a vertical pilot completed with two opposite, stacking, open-hole horizontal drains. A complex compositional evolution of the fluids produced has been observed. A reservoir study integrating geophysics, geochemistry, petrophysics and reservoir engineering assessed the reservoir geometry and the field production behaviour. This allowed the identification of two different phases of hydrocarbon migration that were geologically constrained according to the structural evolution of SE Sicily. The 3D structural reconstruction of the field, built with a Shared Earth Model, was utilized as input to a 3D dual porosity numerical model. The dynamic simulation allowed identification of the drilling location of an additional non-conventional well aimed at draining undeveloped reserves. The study used advanced laboratory methodologies for fluid characterization, state-of-the-art methods for analysing the reservoir fracture network and properly designed modules for simulating non-conventional completions in a 3D dynamic model.
The origin of overpressure in the Carnarvon Basin, Western Australia: implications for pore pressure prediction
Authors: van Ruth Peter , Hillis Richard , Tingate Peter
Published: October 2008

Porosity–effective stress analysis of 37 wells in the Carnarvon Basin, Australia, has identified 12 wells where the overpressure was generated by disequilibrium compaction and four wells where the overpressure was generated by fluid expansion. Disequilibrium compaction was identified as the dominant overpressure-generating mechanism in wells along the Rankin Trend as far south as Gorgon 1 and Spar 1. Fluid expansion was identified as the dominant mechanism of overpressure generation in wells along the Barrow Trend and around the Alpha Arch. Disequilibrium compaction-generated overpressures occur, as would be expected, where the Tertiary sediment thickness is greatest and fluid expansion overpressures where the Tertiary is thinnest. Indeed, where the N-1 (35 Ma) reflector is greater than
c
. 1500 m below seabed, disequilibrium compaction overpressures are observed and where itis shallower than
c
. 1500 m, fluid expansion overpressures are observed. Acoustic log-based pore pressure detection using
Eaton's (1975)
method yielded accurate estimates with an exponent of three in Wilcox 1 where the overpressure was generated by disequilibrium compaction, and an exponent of six in Bambra 1 where the overpressure was generated by fluid expansion. If the
Eaton (1975)
technique is to be applied to seismic processing velocities for pore pressure prediction, then an exponent of three can be used where the N-1 horizon is greater than
c
. 1500 m and an exponent of six where the N-1 horizon is less than
c
. 1500 m.
Estimation of oil and gas column heights in prospects using probabilistic basin modelling methods
Authors: Sylta Øyvind , Krokstad Wenche
Published: October 2008

Source rock and reservoir rock properties are often poorly constrained in the exploration for oil and gas. Geological analogues may be used to create source rock and reservoir rock models in areas with only sparse well data coverage. Exploration risks are often influenced by uncertainties in the rock facies models. This paper outlines a methodology for assessing the consequences of using two or more source and reservoir models on hydrocarbon phase distributions in prospects.

Each source rock and reservoir rock scenario is represented by computerized maps (grids) of thickness, porosities and other properties. The uncertainties of each scenario are described using probabilistic properties. The reservoir thickness may be represented by a uniform distribution with the mean described using a map (grid) with a standard deviation of, for example, 50 m. A Monte Carlo simulation is carried out for this part of the petroleum system and the resulting probabilities of oil and gas in prospects are compiled by weighting each run to calibration wells. The results can be plotted as a map of most likely oil and gas column heights. An uncertainty map is also plotted. The results can be used to rank drilling locations with respect to large oil columns and low uncertainties. The oil and gas column probabilities can be estimated for each well location.

As (more) wells are drilled within a petroleum system the best match simulations can be used to further refine predictions as well as to create an updated map of the petroleum system.
Organic geochemical characteristics of the bituminous Eocene units in the Çorum–Suluova Basin, Central Anatolia, Turkey
Authors: Altunsoy M. , Özçelik O. , Yalçin Erik N.
Published: October 2008

In the Çorum–Suluova Basin (central Anatolia) the Eocene Çeltek and Armutlu formations consist of conglomerate, sandstone, siltstone, marl, mudstone, shale, limestone, clayey limestone, bituminous shale and coal. Total organic carbon (TOC) values in the Çeltek Formation range between 0.1 and 8%. Rock-Eval analyses on core samples with the highest TOC values give hydrogen index (HI) values from 45–846 mgHC g
−1
TOC and oxygen index (OI) values from 9–64 mgCO
2
 g
−1
TOC. The organic matter can be classified as Type I and Type II kerogen on the modified van Krevelen diagram.
T
max
values vary between 428° and 440°C, with an average of 436°C, indicating the catagenesis stage. Based on the microscopic studies, organic matter is composed of predominantly autochthonous algal and amorphous material, with a minor contribution of terrestrial material. The Çeltek Formation can be regarded as a source rock for hydrocarbons. The TOC content of the Armutlu Formation is poor. Samples consist of terrestrial and reworked organic matter. Vitrinite reflectance values are between 0.27% and 0.43%, with an average of 0.34%.
T
max
values are between 433°C and 436°C, with an average of 435°C. The HI value is between 29 mgHC g
−1
TOC and 39 mgHC g
−1
TOC. Considering the data, the Armutlu Formation cannot be the source rock.
Definition and practical application of mudstone porosity–effective stress relationships
Authors: Yang Yunlai , Aplin Andrew C.
Published: October 2008

The relationship developed in soil mechanics between void ratio and vertical effective stress is a simple but practical way of describing the one-dimensional, mechanical compaction of fine-grained, clastic mudstones. The compression coefficients (e
100
and ß) that define this relationship are strongly influenced by grain size, which can be simply described by the sediment's clay content. In this paper, data both from the soil mechanics literature and from geological samples from the North Sea and Gulf of Mexico are used to construct the relationship between clay content and compression coefficients. The two datasets yield different values for the coefficients, but the authors believe that the coefficients derived from the large geological database should be used to describe geological compaction. Regression of the geological data generates the following relationships between clay content and compression coefficients:

\batchmode \documentclass[fleqn,10pt,legalpaper]{article} \usepackage{amssymb} \usepackage{amsfonts} \usepackage{amsmath} \pagestyle{empty} \begin{document} e_{100}{\,}={\,}0.3024{\,}+{\,}1.6867clay{\,}+{\,}1.9505clay^{2}\end{document}

\batchmode \documentclass[fleqn,10pt,legalpaper]{article} \usepackage{amssymb} \usepackage{amsfonts} \usepackage{amsmath} \pagestyle{empty} \begin{document} {\beta}{\,}={\,}0.0407{\,}+{\,}0.2479clay{\,}+{\,}0.3684clay^{2}\end{document}

There is excellent agreement between true porosities and porosities calculated using the standard soil mechanics compaction equation with these coefficients. This indicates that the mechanical compaction of natural mudstones to 40 MPa can be adequately described using the soil mechanics approach. Practical application of the work is a two-stage process which first involves the evaluation of clay content and, thus, compression coefficients directly from wireline log data. These data can then be used to (a) help define effective stress–porosity inputs for basin models and (b) estimate mudstone pore pressures. Examples of pore pressure estimates are shown from west Africa, the North Sea and the Gulf of Mexico.
Peat biomass and early diagenetic controls on the paraffinic oil potential of humic coals, Canterbury Basin, New Zealand
Authors: Sykes R.
Published: October 2008

Early mature, Pukeiwitahi Formation (Late Cretaceous) coals from Galleon-1 and Endeavour-1 wells in the Canterbury Basin, New Zealand have been analysed by petrographic, bulk chemical and thermal extraction- and pyrolysis-GC techniques and compared with similar coals in the Taranaki Basin to determine the primary controls on their paraffinic oil potential. The Pukeiwitahi coals, which are moderately perhydrous (HI 180–305 mgHC g
−1
TOC), vitrinite-rich (73–95%) and relatively liptinite-poor (<10%), accumulated in gymnosperm-dominated, planar mires in a temperate, coastal plain environment. Pyrolysate compositions are representative of high-wax, paraffinic–naphthenic–aromatic crude oil-generating coals. Petrographic data and the
n
-alkyl chain length distributions of extracts and pyrolysates suggest that the long-chain aliphatic hydrocarbons are derived primarily from leaf-derived liptinites (cutinite and liptodetrinite). The paraffinic oil potential of the coals is accordingly dependent on the net amount of leaf biomass in the precursor peats, following partial degradation of the available leaf litter under generally high surface water levels and dilution with other, less paraffinic biomass, particularly wood. The coals in Endeavour-1 generally contain more leaf-derived liptinites than those in Galleon-1 and, thus, have greater paraffinic oil potentials despite commonly lower HI values. Brackish conditions within the depositional environment caused the Galleon-1 and Endeavour-1 coals to be variably enriched in hydrogen but not in aliphatics. HI is, therefore, not a reliable indicator of the paraffinic oil potential of marine-influenced coals.
Influence of porosity and pore fluid on acoustic properties of chalk: AVO response from oil, South Arne Field, North Sea
Authors: Japsen Peter , Bruun Anders , Fabricius Ida L. , Rasmussen Rasmus , Vejbæk Ole V. , Pedersen Jacob Mørch , Mavko Gary , Mogensen Christian , Høier Christian
Published: October 2008

Amplitude versus offset (AVO) inversion provides direct evidence for the presence of light oil in high-porous chalk in the South Arne Field, North Sea. The elastic properties of the chalk were estimated at three scales by analysing core data, log-readings and AVO-inversion results. The velocity–porosity relation of the core data matches a modified upper Hashin–Shtrikman model for Ekofisk Field chalk and the model is extended to 45% porosity. A small clay content reduces porosity without affecting chalk stiffness and this content can be estimated from the water saturation, which is controlled by silicate content and particle sorting in the zone of irreducible water saturation. The model is, thus, scaled according to clay content estimated by the water saturation. Based on comparison with the model and measurements on core samples, it is found that the sonic log data represent chalk characterized by forced displacement of the oil by mud filtrate and, thus, a much higher water saturation than estimated from, for example, a shallow resistivity log. Forward modelling of the acoustic properties of the virgin zone results in a characteristic pattern of Poisson ratio versus depth. This pattern agrees with inverted seismic data, whereas it is not captured by conventional fluid substitution.
Upscaled models of flow and transport in faulted sandstone: boundary condition effects and explicit fracture modelling
Authors: Flodin Eric A. , Durlofsky Louis J. , Aydin Atilla
Published: October 2008

Faults formed by shearing of joint zones in sandstone contain fine-scale features that cannot be represented explicitly in large-scale flow simulations. Upscaled models are, therefore, required for reservoir engineering computations. These models attempt to capture fine-scale effects through equivalent permeabilities that are computed from the underlying fine-scale characterization. In this paper the impact of several different local boundary conditions on the calculated equivalent permeability is assessed. Pressure–no-flow, periodic and mirror-periodic boundary specifications are considered. The resulting coarse-scale permeability tensors are shown to be highly dependent on the local boundary conditions used in the models. In cases with through-going high-permeability features, pressure–no-flow and mirror-periodic boundary conditions provide upscaled permeabilities that correctly capture global flow characteristics. Periodic boundary conditions, by contrast, are more suitable for systems lacking through-going high-permeability features. This sensitivity to boundary conditions calls into question the robustness of the equivalent permeability for the general case and suggests that dominant through-going features would best be modelled explicitly. In addition, due to the very small thickness and high permeability of some through-going structural features (e.g. slip surfaces), globally upscaled models are inadequate for the modelling of transport. To address these issues, a ‘partial upscaling’ method – removing the through-going high-permeability features from the fine model, upscaling to a coarse grid and then reintroducing the high-permeability features back into the coarsened model – is adopted. This procedure is shown to provide coarse models that give accurate predictions for both flow and transport.
An example study using conventional 3D seismic data to delineate shallow gas drilling hazards from the West Delta Deep Marine Concession, offshore Nile Delta, Egypt
Authors: Sharp Andy , Samuel Andy
Published: October 2008

This paper details a study that was completed at the end of 1999 to investigate the suitability of using existing, high quality, conventionally processed 3D seismic data (hereafter 3D data) to replace specifically commissioned 2D seismic site survey data (hereafter 2D site data). For this study, three wells from an existing dataset of six in the West Delta Deep Marine Concession, offshore Egypt (WDDM) were investigated. A prescriptive workflow was developed using the 3D data and the results compared to those obtained from a conventional previously commissioned 2D digital site survey dataset. For this dataset from WDDM, the results obtained from the 3D data and the 2D data were similar, the main difference being that more numerous, smaller probable hazards were prognosed by the 3D data. After undertaking this investigation and following an independent review of the results, a recommendation was made to operate the 2000 WDDM drilling campaign using hazard prognosis from the conventional 3D data, i.e. not to acquire well-specific, new digital site surveys. This recommendation was followed and five exploration wells were drilled in 2000 with no specific, digital site survey data being acquired.No safety, operational or environmental implications were encountered as a result of this replacement and significant operational savings accrued to the operating partnership.
From seismic to bed: surface–subsurface correlations within the turbiditic Cellino Formation (central Italy)
Authors: Carruba S. , Casnedi R. , Felletti F.
Published: October 2008

The area east of the Gran Sasso Chain in central Italy has been explored in detail because it holds a hydrocarbon field (Cellino Field), located in the Lower Pliocene foredeep turbidites of the Cellino Formation. Correlation has been made between the hydrocarbon-bearing sedimentary bodies and the same stratigraphic intervals cropping out only few kilometres to the west. The area, thus, offers a rare example where comparison can be made between lithofacies – observed in the field, electrofacies – displayed by the electric logs of the wells, and seismofacies – revealed by seismic survey.

This surface–subsurface integrated study of the Cellino Formation has revealed the presence of different turbiditic facies associations, their related electrical expressions and the possibility of a seismostratigraphic subdivision of the unit. These correlations exemplify the different resolution of these three complementary methods of investigation.
Analysis of petroleum system criticals of the Matruh–Shushan Basin, Western Desert, Egypt
Authors: Metwalli Farouk I. , Pigott John D.
Published: October 2008

A systematic analysis of petroleum system criticals can provide a robust review of a basin's hydrocarbon potential through time and space. The ten essential petroleum system criticals that express the extensive and intensive variables are: source generation volume (S
gv
), source-rock richness (S
gr
), source-rock quality (S
rq
), source-rock maturity (S
rm
), reservoir rock volume (R
rv
), reservoir rock quality (R
rq
), reservoir rock hydrocarbon type (R
rhct
), reservoir rock seal and closure (R
rsc
), flux migration path (F
mp
) and petroleum system timing (PS
t
). The Matruh–Shushan Basin of the Western Desert, Egypt, forms the basis for an example of the application of this technique.

Modelling and empirical data of source-rock criticals reveal that the Mesozoic source generation megasequence is restricted in the Matruh–Shushan Basin. Presently, these areas lie buried at their maximum experienced temperatures. Potential reservoirs in portions of the north and central Western Desert were dependent upon lateral migration path criticals for their charge. Progressive uplift and basin inversion since the middle Palaeozoic provided favourable conditions for lateral migration in the Mesozoic. The main potential source rocks in the present basins are the Lower Cretaceous Alam El Bueib (AEB) and the Jurassic Khatatba. Although both share mixed kerogen types (II/III), they attained their highest levels of thermal maturity at different times. Basin modelling suggests the Lower Cretaceous AEB entered the oil window in the Late Cretaceous, while the Jurassic Khatatba of the deeper part of the basin entered the oil window in the Turonian.

Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower post-Late Cretaceous structured reservoirs.

Basin modelling incorporating an analysis of the petroleum system criticals has outlined the spatial and temporal extent of the different petroleum systems in the Matruh–Shushan Basin and can help guide the next exploration phase. While oil exploration is now focused appropriately along Late Cretaceous and Tertiary migration paths, these results suggest deeper sections may have reservoirs charged with significant unrealized gas potential.
Wettability alteration in petroleum systems: the role of polar non-hydrocarbons
Authors: Bennett B. , Buckman J. O. , Bowler B. F. J. , Larter S. R.
Published: October 2008

Compositional changes amongst surface active components of petroleum are brought about by crude oil/brine/rock interactions. The behaviour of petroleum components following simulated petroleum migration through an initially water-saturated continuous siltstone (89.7 cm × 5 cm) core was investigated. A suite of produced oils and core extract petroleum from the core-flood experiment were analysed by Iatroscan and Gas Chromatography-Mass Spectrometry (GC-MS). Dramatic changes were observed in the composition and distributions of polar non-hydrocarbons, namely, fluoren-9-ones, carbazoles, benzocarbazoles and C
0
–C
3
phenols indicating varying degrees of surface activity within the core-flood system.

Following flooding, environmental scanning electron microscopy (ESEM) was used to view water condensation behaviour on freshly exposed core chips. Samples prepared from the original unflooded core and core material sectioned towards the outlet of the core flood displayed surfaces exhibiting hydrophilic tendencies. Meanwhile, hydrophobic behaviour was observed in a sample from the core inlet. The ESEM descriptions of the interaction of water on core surfaces appear to be consistent with the compositional changes encountered in the core extract petroleum. Wettability was altered most strongly at the core inlet where surface active compounds are rapidly removed from the migrating petroleum. In particular, small hydrophilic moieties, such as alkylphenols, appear to rapidly precondition mineral surfaces, changing wettability and subsequently allowing larger hydrophobicmolecules to sorb. Hence, petroleum surface active compounds are capable of rapidly (days to months) facilitating wettability alteration in crude oil/brine/rock systems that are initially water wet.
A probabilistic approach to improved geological knowledge and reduced exploration risks using hydrocarbon migration modelling
Authors: Sylta Øyvind
Published: October 2008

This paper elaborates a methodology for assessing the consequences of uncertainties in the source and reservoir models on hydrocarbon phase distributions in prospects by improving the
a-priori
probability distributions. The uncertainties of geological systems can be described by probabilistic distributions of quantified geological variables, such as source rock and reservoir thicknesses. A Monte Carlo simulation of hydrocarbon generation, expulsion, migration and entrapment is carried out with probabilistic distributions defining important input variables. A weight for each simulation run is computed from a misfit function that describes how well the modelled oil and gas columns fit the observed columns in a set of calibration wells. These weights are used to compile
a-posteriori
probability distributions of the input variables. The resulting probability distributions, therefore, describe the uncertainties of the geological system after the calibration of the migration model.

In a demonstration example from the Tampen Spur area of the North Sea, the most sensitive geological input distributions become significantly narrower, thus limiting the range of possible outcomes. Other distributions become more uneven, with peaks and lows. The changes in the variable distributions have been quantified and variables can, therefore, be ranked with respect to their impact on changes in probabilities for key outcomes. A large number of simulation runs is required for the proposed method to be effective because many simulation runs result in too large a misfit. A statistical fit of a second-order function to the misfit values allows for the effective screening of input variables, thus reducing the computing time, in the demonstration example, to 15% of the unscreened times. The result of the analysis is that the effect of geological uncertainties on output values is effectively reduced and that a quantitative learning has been obtained. This knowledge can be applied in other hydrocarbon generation and migration studies within the study area, allowing for more rapid and more accurate estimates of oil and gas resources before drilling.
Reservoir modelling and simulation of Lajas Formation outcrops (Argentina) to constrain tidal reservoirs of the Halten Terrace (Norway)
Authors: Brandsæter Inge , McIlroy Duncan , Lia Oddvar , Ringrose Philip , Næss Arve
Published: October 2008

Three-dimensional geological modelling and reservoir simulations of an outcrop analogue to reservoirs of the Halten Terrace, offshore mid-Norway, are presented. The model of the outcrop incorporates (a) a detailed sedimentological understanding, (b) a set of stochastic realizations highly-constrained to the geological models and (c) streamline waterflood flow simulations assuming typical subsurface petrophysical properties from the Halten Terrace. Statistical analysis of simulation results has been used to show the importance of both the facies architecture and the spatial petrophysical model. The outcrop model has significantly improved the estimation of facies dimensions and architecture and gives a valuable insight into understanding petroleum reservoirs of the Halten Terrace.
A 3D stochastic model integrating depth, fault and property uncertainty for planning robust wells, Njord Field, offshore Norway
Authors: Rivenæs Jan C. , Otterlei Cecilie , Zachariassen Eli , Dart Chris , Sjøholm Jorunn
Published: October 2008

The Njord Field, situated in the Haltenbanken area, is one of the most challenging reservoirs on the Norwegian shelf. The structural complexity is high, with numerous intersecting faults compartmentalizing the reservoir. The reservoir is dominated by alternating shale and sand intervals of tidal, estuarine and deltaic depositional origin.

One of the main segments on Njord – the Central Area – was the target for a one-year improved oil recovery study. The Central Area reservoir is produced by depletion, with a current recovery factor of only 6%, as most faults appear to seal during production. The previous drilling experience revealed quite large uncertainty with respect to both depth and missing faults due to poor seismic data quality.

In order to plan further wells in this area a model that comprises the full uncertainty with respect to both structural components (depth uncertainty and faults) and property components (facies, permeability, porosity) was made. The model was built by combining commercial modelling software (IRAP RMS and STORM:HORIZON) with an R&D tool (HAVANA) in a manner that has not been attempted previously, and 200 stochastic realizations were run. Each realization has a different structural 3D grid (depth and fault pattern) and different petrophysical properties. A streamline simulator in IRAP RMS was applied to rank the realizations and ten realizations were chosen for further well screening in the flow simulator (ECLIPSE). The model was applied to propose two new well targets that were robust economically (given all uncertainty). In addition, the model was applied in testing various unconventional well types, for example so-called ‘connector-wells’, which are open holes in the reservoir (but not connected to the surface), in order to connect fault blocks bounded by sealing faults.

Drilling and subsequent seismic interpretation after the model had been built revealed that the structural uncertainty was even greater than predicted. It is crucial to capture the full interpretation uncertainty and, in particular, to address the problem of jump-correlation across fault blocks. Despite this, however, the observed cumulative production from the new oil producer compares well with the prognosis from the model.