bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of quantitative palaeobathymetry in basin modelling, with reference to the northern North Sea
Authors: Kjennerud Tomas , Sylta Øyvind
Published: November 2010

The effect of using quantitative palaeobathymetric input in 1D tectonic modelling, 2D forward siliciclastic depositional modelling and 3D hydrocarbon migration modelling has been tested and quantified for northern North Sea datasets. In order to perform the latter, a 3D method for restoring palaeobathymetry has been developed, based on a previously documented 2D geometrical approach. Quantitative palaeobathymetry constrains the basin shape through geological time. Bathy-metric input has been shown to be important in defining tectonic phases in the post-rift phase in the northern North Sea and to constrain the possibility for slope failure and mass flows. In hydrocarbon migration modelling, it has been shown that palaeobathymetric input may change the migration direction through time, compared to modelling runs performed with no palaeobathymetric input.
The geological structure and petroleum potential of the Kola-Kanin Monocline, Russian Barents Sea
Authors: Ivanova N. M.
Published: November 2010

The Kola-Kanin Monocline has been recently recognized as a potentially prospective region for hydrocarbon discoveries. There may be good generating potential within Riphean grabens. Sedimentary sequences of the Riphean subplatform and Vendian terrigenous deposits could contain hydrocarbons. The top of the Riphean section is now a monoclinal surface dipping NE towards the South Barents Basin. The surface of the monocline is complicated by highs and ridges, which trend NW along the coast of the Kola Peninsula. Here, prospective plays may be present in the form of anticlinal and fault-controlled traps in Riphean to Carboniferous rocks, as well as in pinch-outs of Devonian and Carboniferous clastic rocks. In the central and northern parts of the monocline, prospects can be expected at accessible depths, mainly in Carboniferous to Permian carbonate build-ups, but also in Upper Devonian and Silurian build-ups: the Permian carbonates are the main exploratory targets. In the basinward part of the monocline, stratigraphic and lithologic traps may occur in Upper Permian clinoform sandstones and in Triassic sandbars.
Factor analysis of seismic multiattributes for predicting porosities using sequential nonlinear regression: the thin carbonates of the BMB Field, Poland
Authors: Elsayed Raef A. , Slusarczyk Ryszard
Published: November 2010

For a thin reservoir, such as the Zechstein Main Dolomite (generally 33–83 m thick) of the BMB oil and gas field of Poland, where the thickness (
c.
40 m) is often around a quarter of the dominant wavelength, the composite seismic response results from variations in the petrophysical properties, thickness, lithology, effective pressure and temperature, as well as in the acoustic impedance of the encasing materials. To use the BMB Field 3D seismic data for porosity prediction, 20 post-stack attributes were extracted from a seismic volume, defined by two zero-crossing time horizons that bound the reflections of the Main Dolomite. Because of the large number and the interdependency of the extracted attributes, principal component factor analysis was applied, resulting in the coding of 70% of the variability of the extracted attributes, in six orthogonal factors. Sequential nonlinear regression revealed that the first three factors,
F1
,
F2
and
F3,
are the significant predictors of porosity. Cross-validation indicated a class of poorly estimated porosities resulting from poor quality/complexities in the seismic data, and a class of good porosity estimates that were subsequently used in a final cross-validation for establishing optimum weights and orders of porosity prediction polynomials. The final cross-validation indicated optimum orders of five, three and two for polynomials in
F1
,
F2
and
F3
, respectively and optimum weights corresponding to validation well No. 1 (MO-3).
Overpressure phenomena in the Precaspian Basin
Authors: Anissimov Leonid
Published: November 2010

Overpressured zones in the Precaspian Basin occur at depths below 4000 m. The most extensive zone is in the subsalt reservoirs throughout the basin. In spite of the extended literature database on overpressure phenomena, the Precaspian Basin and its Palaeozoic rock sequence is of a special interest because of its long geological history. The delineation of overpressure generation in the completely compacted sediments is very important in order to exclude disequilibrium compaction as the most significant overpressure mechanism for the Tertiary basins. Seal effectiveness and pressure compartment longevity have mainly resulted from other processes: origin of secondary minerals, hydrocarbon saturation and bitumen incorporation in mudrocks. Solid bitumen precipitation in clays forms a more perfect seal than the capillary pressure. The Astrakhan gas field is the best example, where the compositional evolution of formation fluids has changed the clay permeability.
The distribution of Cretaceous and Paleocene deep-water reservoirs in the Norwegian Sea basins
Authors: Vergara Luis , Wreglesworth Ian , Trayfoot Mark , Richardsen Geir
Published: November 2010

Facies maps for selected Cretaceous and Paleocene deep-water sandstone reservoirs in the Norwegian Sea constitute an exploration tool and allow description of the basin infill in relation to tectonic phases. Sequences K40 (middle–late Albian) and K60 (middle–late Cenomanian) formed in an immature basin where most of the fan systems and slumps were derived from local highs. Sequence K80 (Coniacian–late Santonian) contains sandstones interpreted to be slumped deposits in parts of the Halten and Dønna terraces (Lysing Formation), but with fans of widespread extent in the Vøring and northern Møre Basin. The K85–K90 sequence set (early Santonian–late Campanian) contains sandstones equivalent to the Nise Formation that are the main potential reservoirs in the Vøring Basin; they were fed by multiple entry points and developed into areally extensive basin floor thicks. Sequence Pg10 (Danian–Selandian: ‘Egga’ Member) is interpreted to comprise a basin floor fan in the Ormen Lange discovery. During this cycle the Halten Terrace rotated eastwards exposing Upper Cretaceous mudstones. Vast amounts of sediment were deposited in the western Møre and Vøring Basin around new exposed areas.
Source potential of the Mesozoic–Cenozoic rocks in the South Caspian Basin and their role in forming the oil accumulations in the Lower Pliocene reservoirs
Authors: Feyzullayev Akper A. , Guliyev Ibrahim S. , Tagiyev Mushfig F.
Published: November 2010

The source potential and organic maturity of the shales alternating with the reservoir beds in the Lower Pliocene Productive Series – the major oil-bearing unit in the South Caspian Basin – are inadequate to have formed the observed petroleum accumulations. A geochemical study of rocks collected from wells and outcrop localities has been carried out to assess the oil- and gas-generative properties of the Middle Jurassic to Lower Pliocene sediments of the basin. On the whole the section under review is characterized by poor to good organic richness and low hydrogen index, suggesting type 2 and 3 kerogens. Organic-rich sediments are relatively frequent in parts of the Oligocene–Miocene interval. Source-to-oil correlation based on carbon isotope signatures points to a largely epigenetic origin for the oils reservoired in the Lower Pliocene. Isotopically, the oils in these Productive Series reservoirs are best correlated with organic matter contained in the Miocene sediments.
Coupled changes in pore pressure and stress in oil fields and sedimentary basins
Authors: Hillis Richard R.
Published: November 2010

Repeated pressure measurements undertaken throughout the depletion of oil fields demonstrate that reduction in pore pressure is accompanied by a reduction in total minimum horizontal stress (σ
h
), a phenomenon described herein as oil field-scale pore pressure/stress (
P
p
/σ
h
) coupling. Virgin pressure measurements (i.e. those unaffected by depletion) through normally and overpressured sequences in sedimentary basins demonstrate that overpressure development is accompanied by an increase in σ
h
, described herein as sedimentary basin-scale
P
p
/σ
h
coupling. With depletion of the Ekofisk Field, North Sea, minimum horizontal stress decreased at approximately 80% of the rate of reduction of reservoir pore pressure (i.e. Δσ
h
/Δ
P
p
≈0.8). Virgin pressures measured in exploration wells surrounding the Ekofisk Field (Norwegian quadrants 1 and 2) indicate that with overpressure development Δσ
h
/δ
P
p
≈0.73 (assuming shallow, normally pressured sequences are representative of overpressured sequences prior to overpressure development). Hence, despite the different temporal and spatial scales, the rate of decrease of minimum horizontal stress with pore pressure due to depletion of the Ekofisk Field is similar to the rate of increase of minimum horizontal stress with pore pressure due to overpressure development in the surrounding region. Basin-scale exploration pressure data in the Ekofisk region may thus provide an indication of the reservoir stress changes associated with depletion. Knowledge of such stress changes is critical because they can lead to the collapse of uncased wellbores, sand production and to faulting/fracturing and seismicity with field development.
Achievements and challenges in petroleum geostatistics
Authors: Dubrule Olivier , Damsleth Eivind
Published: November 2010

The current use of geostatistics in the petroleum industry is reviewed and the main issues that need to be tackled before the potential of geostatistics is fully realized are highlighted. The paper reviews and discusses three main topics: (1) geostatistics and geology; (2) multidisciplinary data integration; and (3) uncertainty quantification with multiple realizations. Our main message is that geostatistics has come a long way and reached maturity. In the years ahead, geostatisticians should focus less on the development of new algorithms and more on the training of geoscientists and the development of new work flows for decision support with geostatistics as the core.
Predicting oil recovery using percolation theory
Authors: King P. R. , Buldyrev S. V. , Dokholyan N. V. , Havlin S. , Lee Y. , Paul G. , Stanley H. E. , Vandesteeg N.
Published: November 2010

In this paper we apply scaling laws from percolation theory to the problem of estimating the time for a fluid injected into an oil field to breakthrough into a production well. The main contribution is to show that, when these previously published results are used on realistic data, they are in good agreement with results calculated in a more conventional way but they can be obtained significantly more quickly. As a result they may be used in practical engineering circumstances and aid decision-making for real field problems.
A multi-scale approach to improve reservoir characterization and forecasting: the Albacora Field (deep-water offshore Brazil) study
Authors: Cunha Luciane B. , Barroso Alberto da S. , Romeu Régis K. , Sombra Cristiano L. , Cortez Marcella M. , Backheuser Yeda , Lopes Marcos F. , Schwerdesky G. , Bruhn Carlos H. , de Souza Rogério S. , Becker Mauro R.
Published: November 2010

The Upper Albian Namorado Sandstone is one of the reservoirs of the Albacora Field, located in the Campos Basin, deep-water offshore Brazil. It is a sand-rich turbidite system where the most important controls on permeability are calcite cementation, thin beds of non-reservoir lithologies and some north–south trending faults. A major multidisciplinary reservoir characterization project was conducted to improve the reservoir description using all available data. In this paper, we focus on how the effect of rock heterogeneities were represented in the fluid flow model and on the performance obtained from this model. The basic idea was to define a hierarchical model of facies established on the basis of three main work scales: porous systems (thin sections and core sample scale); composite facies (whole core and log scale); and seismic facies (interwell to field scale). An up-scaling technique, based on the geopseudo concept, was used to generate the effective petrophysical properties for the fluid-flow simulation model. A Markov–Bayes geostatistical simulation method was applied in facies stochastic modelling. The sophisticated model that was built allowed very fast history matching.
Ranking of stochastic realizations of complex tidal reservoirs using streamline simulation criteria
Authors: Brandsæter Inge , Wist Hanne Therese , Næss Arve , Lia Oddvar , Arntzen Ole Jakob , Ringrose Philip S. , Martinius Allard W. , Lerdahl Thomas Rage
Published: November 2010

This study concerns the modelling of complex tidal heterogeneities found in the Lower Jurassic Tilje Formation offshore mid-Norway. The Tilje Formation is characterized by tidal channels, tidal bars (shoals), tidal flats and deltaic deposits. The lithofacies associations have been modelled as large-scale objects with a wide range of shapes (channels, sheets and lobes). In addition small-scale models of the internal bedding structure have been generated in order to calculate effective permeability values at appropriate modelling scales.

In order to assess the influence of the static input factors on recovery predictions, several production response variables were recorded for each of the 120 realizations generated. These include: streamline densities, breakthrough time measured in movable pore volume injected, pore volume tracer injected at 50% and 95% tracer fraction in the producer, and recovery factor of movable pore water at 95% tracer fraction in the producer. For this purpose we used a streamline reservoir simulator (Frontsim) with a tracer option (single-phase flow simulations).

By using analysis of variance, we identified the following parameters which have the largest influence on single-phase fluid flow: (1) dimension of large-scale bar objects; (2) effective permeabilities of marginal (background) facies; and (3) interaction effects between bar objects and background permeabilities. In addition, the effective permeability values of the marginal facies are highly controlled by certain thresholds in mud content.
Methods for quantifying the uncertainty of production forecasts: a comparative study
Authors: Floris F. J. T. , Bush M. D. , Cuypers M. , Roggero F. , Syversveen A-R.
Published: November 2010

This paper presents a comparison study in which several partners have applied methods to quantify uncertainty on production forecasts for reservoir models conditioned to both static and dynamic well data. A synthetic case study was set up, based on a real field case. All partners received well porosity/permeability data and ‘historic’ production data. Noise was added to both data types. A geological description was given to guide the parameterization of the reservoir model. Partners were asked to condition their reservoir models to these data and estimate the probability distribution of total field production at the end of the forecast period. The various approaches taken by the partners were categorized. Results showed that for a significant number of approaches the truth case was outside the predicted range. The choice of parameterization and initial reservoir models gave the largest influence on the prediction range, whereas the choice of reservoir simulator introduced a bias in the predicted range.
Conditioning to dynamic data: an improved zonation approach
Authors: Le Ravalec-Dupin Mickaële , Nœtinger Benoît , Hu Lin-Ying , Blanc Georges
Published: November 2010

An optimization method for incorporating dynamic data into reservoir modelling is presented. It integrates a very typical feature of the zonation approach that is based upon dividing the reservoir model into subregions. Solving the optimization problem consists of adjusting the subregion pattern so that the reservoir model duplicates the observed dynamic behaviour. Unlike the traditional approach, permeabilities in subregions are not constant, but show spatial variations. A variogram model that is the same for all the subregions describes this variability. The suggested method allows for optimization of permeability distributions within the subregions while preserving the second-order statistics for the whole reservoir model as well as the spatial continuity between subregions. It remains as flexible as the traditional zonation approach although it can handle complex structures.
Integrated scenario and probabilistic analysis for asset decision support
Authors: Floris Frans J. T. , Peersmann Martin R. H. E.
Published: November 2010

In recent years, much effort has been spent in integration of the hydrocarbon E&P business processes. The new challenge lies in the use of the generated data for decision-making. In particular, in hydrocarbon assets, where large uncertainties occur, it is important to include the formal quantification of these uncertainties in the integrated workflow and allow for a decision framework based on a full characterization of these uncertainties.

For quantification of uncertainties two classes of approach are currently in use –the probabilistic approach based on the description of a stochastic model for capturing all uncertainty and the scenario approach based on a definition of a number of conceptually different models expressing the uncertainty. Some hybrid versions of the approaches exist as well. The pros and cons of these approaches are discussed. Following this, an extended statistical framework is presented in which the previous approaches to subsurface uncertainty modelling have been combined. The framework is not limited to subsurface uncertainties, but can also be applied to the other uncertainties and decisions in the asset model. In the integrated framework several scenarios may be identified for the static earth model, the dynamic earth model, the drilling model, the surface facilities model and the economic model. A scenario tree can represent the combination of all these scenarios.

Within each scenario a stochastic model can be applied to capture the within-scenario uncertainty. Calculation rules for the integration of the stochastic and scenario uncertainties are presented. Finally, decision rules are given that allow for decision-making based on the full uncertainty span in the integrated asset framework.
Synthetic well test modelling in a high net-to-gross outcrop system for turbidite reservoir description
Authors: Robertson Ewan , Corbett Patrick W. M. , Hurst Andrew , Satur Nick , Cronin Bryan T.
Published: November 2010

Synthetic well tests have been produced using a 3D model of an outcropping turbidite sandstone unit from the Cingöz region in southern Turkey. The model contains realistic sand sheet, tongue, lobe and background sand facies architecture (i.e. geometry and stacking) mapped from an outcrop study. The geometric information is useful as an analogue for high net-to-gross turbidite oil fields. The facies have been assigned petrophysical properties from a subsurface analogue. There is little shale in this system. Well test responses were then derived from the high net-to-gross turbidite model using various architectural, porosity–permeability scenarios and completion strategies. The impact on well test derivatives of various sand body geometries and permeability contrasts could then be determined. Two completion strategies – partial penetration and fully perforated intervals – were assessed for their applicability in the high net-to-gross system.

The geological model is effectively a sandbox, and shows a very uniform testing response from the rather uniform property distributions. However, when the level of permeability heterogeneity is increased by populating the model with varying contrasts of permeability and porosity, the sand body geometry can be seen to influence the well tests. Partial completions in sand bodies are particularly effective in detecting sand body geometry. The geometry controls the flow regimes in a well test response despite variations in the permeability contrasts. The effect of varying geometry is illustrated and an external linear flow regime is identified. Where there is sufficient sand body thickness, partial perforation results in spherical flow, from which a vertical permeability can be obtained. In the model, the vertical permeability thus obtained is a local (to the volume investigated) effective permeability of stacked isotropic facies.

This work was undertaken to give guidance on the description of hydrocarbon reservoirs by well testing. If well testing is to be used in high net-to-gross turbidite systems for the purposes of reservoir characterization, then partial perforation of the system should be planned. Interpreted vertical permeabilities should be applied with careful consideration of the stacked pattern of sand bodies.
Multi-target wells: a new concept to improve well economics
Authors: Sackmaier W. E.
Published: November 2010

The Vienna Basin is a sedimentary basin more than 10 km in thickness and composed of more than a dozen hydrocarbon layers. Since the area has been intensively explored in the past 50 years, future exploration can expect to find only small reservoirs or compartments of already existing reservoirs. However, the existing infrastructure, such as pipelines, facilities and a nearby refinery, would make even small finds attractive. In this light it is of vital importance to reduce risk and costs in hydrocarbon exploration and production.

Multi-target wells were found to be an adequate answer to these problems: the chance of discovery increases more or less directly with the number of targets included in the well trajectory; and several small reservoirs can, in total, provide positive well economics. Moreover, by including exploration, appraisal and production targets into one well path a substantial contribution to improve economic hydrocarbon recovery from existing fields can be made. To further reduce drilling costs a new casing philosophy was established. By skipping the intermediate casing across the build-up section substantial savings could be made.

To plan and execute these challenging projects efficiently a multidisciplinary team has to be set up at an early stage of the drilling project. In this way the number of targets, the actual well path and well construction with respect to production requirements can be optimized. An example of a recently drilled multi-target horizontal well, including one primary and five secondary targets, is given. By applying this new concept drilling costs could be reduced by more than 30%.
3D oil migration modelling of the Jurassic petroleum system of the Statfjord area, Norwegian North Sea
Authors: Johannesen J. , Hay S. J. , Milne J. K. , Jebsen C. , Gunnesdal S. C. , Vayssaire A.
Published: November 2010

3D oil migration modelling of the Statfjord area of the Northern North Sea has led to increased understanding of the migration routes and definition of oil migration fairways. The majority of discovered fields in the Statfjord area lie on fault block ridges. Migration modelling demonstrates that they were filled by oil generated from the Viking Graben, East Shetland and Marulk basins, migrating stratigraphically downwards from the Upper Jurassic Draupne Formation source rock into the Middle Jurassic Brent Group sandstones. Thereafter, lateral migration in a fill–spill manner occurred along the axes of the ridges. Locally, petroleum also migrated laterally through both Upper and Lower Jurassic sandstones. The migration modelling has been combined with geochemical source rock and oil correlation resulting in increased confidence. For the first time we have been able to quantitatively model and visualize the complex petroleum system of the area and gain an insight into its development through geological time.
Fluid saturation from well logs using committee neural networks
Authors: Helle Hans B. , Bhatt Alpana
Published: November 2010

Neural computing has made a major step forward by the introduction of multi-net systems in practical applications. In this study we developed and tested a modular artificial neural network system for predicting underground fluids, water, oil and gas, and their partial saturations, directly from well logs, without explicit knowledge of the fluid and rock properties as required by conventional methods. Based on laboratory data on relative permeability for alternative fluid systems –oil–water or gas–oil – respectively, relative permeability logs may also be provided for input to reservoir simulation while drilling.

Simple three-layer back-propagation artificial neural networks (ANN) constitute the building blocks of a modular system, where the input logs are sonic, density, neutron porosity and resistivity. By numerical experiments using synthetic logs we have determined the optimal architecture of the ANN. We find that the overtraining strategy is a suitable technique for bias reduction and an unconstrained optimal linear combination is the best method of combining outputs in the committee neural net. The accuracy of the net is restricted only by accuracy of data. Comparison between ANN predictions of fluid saturation with those of conventional petrophysical analysis, in wells unknown to the network, indicates a standard error of less than 0.03.
The representation of two phase fault-rock properties in flow simulation models
Authors: Manzocchi T. , Heath A.E. , Walsh J.J. , Childs C.
Published: November 2010

Faults are represented conventionally in production flow simulation models using transmissibility multipliers which capture the single phase, but not the two phase, fault-rock properties. Available data indicate that fault-rocks have similar two phase properties to sediments of the same permeability, hence existing methods can be applied to estimate two phase fault-rock properties from their intrinsic permeabilities. Two methods of representing the two phase fault-rock properties implicitly in the flow simulator are compared, using one-dimensional numerical flow models containing water-wet faults with imbibition capillary pressure curves. The method which is the closer two phase analogue of the single phase transmissibility multiplier is inappropriate, as the implementation is unreasonably unwieldy. A simpler implementation is to derive pseudo-relative permeability functions including the fault-rock properties in the upstream grid block; these properties are then incorporated directly in the simulator. Relative transmissibility multiplier functions can be back-calculated from the pseudo-relative permeability functions, and indicate how closely the single phase multiplier approximates two phase flow through the fault. Implementation in a 3D model with complex fault juxtapositions validates the approach, and a practical workflow for the routine inclusion of two phase fault-rock properties in conventional faulted flow simulation models is outlined.
Scale-up of well performance for reservoir flow simulation
Authors: Muggeridge A.H. , Cuypers M. , Bacquet C. , Barker J.W.
Published: November 2010

The method of Ding for scaling-up in the near-well region is evaluated on a variety of two- and three-dimensional problems, including cases with partially penetrating wells and some with non-vertical wells. The method is found to work well for all cases tested although accuracy is in general lower for 3D cases and possibly for wells producing at constant bottom hole pressure. The computational effort involved in the scaling-up can be minimized by use of a reduced computational domain with only a slight degradation of the results. Both well index and modified horizontal transmissibility are required for satisfactory results, but use of modified vertical transmissibility appears to be unnecessary.
Prediction of offshore viscous oil field performance using reservoir simulation
Authors: Balbinski E. F. , Element D. J. , Goodyear S. G. , Jayasekera A. J.
Published: November 2010

Development plans for UKCS viscous oil reservoirs use production profiles predicted by full-field simulation models. The use of horizontal wells, possibly combined with other IOR techniques, and the unusually high vertical permeability of many of the fields, lead to a range of issues that need to be carefully considered when building simulation models.

The strengths and weaknesses of different gridding systems, and the level of areal and vertical grid refinement that is needed, are discussed and illustrated with a range of examples including: interpretation of Extended Well Test results and integration with full-field modelling; sensitivity to relative permeability assumptions; prediction of gas movement from primary gas caps; and the comparison of different IOR techniques.

Where horizontal wells are drilled to reduce gas coning, undulations in the well trajectory can cause local coning of free gas, giving significantly earlier breakthrough times compared to strictly horizontal wells. A good correlation is found between effective stand-off and breakthrough time. Where localized gas production occurs, scoping calculations suggest that inflow of oil from further down the wellbore may be significantly reduced by multi-phase friction effects and gravity potential terms not modelled in conventional simulators.
Sedimentation during halokinesis: Permo-Triassic reservoirs of the Saigak Field, Precaspian Basin, Kazakhstan
Authors: Barde Jean-Pierre , Chamberlain Paul , Galavazi Martin , Gralla Peter , Harwijanto Josef , Marsky Juergen , van den Belt Frank
Published: November 2010

Permo-Triassic reservoirs of the Saigak Field, in the eastern part of the Precaspian Basin of Kazakhstan, produced oil at cumulative rates exceeding 3600 BOPD. This confirms the attractiveness of the post-salt play in this part of the basin. Core studies show that cross-bedded sandstones in braided fluvial channels, alluvial and delta plain deposits are the best reservoirs. Integration of topographic and geomorphological features with satellite and seismic data led to the identification of inter-dome depressions with present-day active subsidence and sedimentation. These depressions are analogues to Permo-Triassic mini-basins. In the wells, reservoirs deteriorate quickly as soon as depositional environments become evaporitic. Seismic inversion was applied on a small 3D data-set covering the Saigak Field. The reduction of porosity with depth correlates well with increasing acoustic impedance values. In the inverted volume, reservoirs were characterized in terms of porosity and connected bodies, an essential input into static and dynamic reservoir modelling.
The use of leak-off tests as means of predicting minimum
in-situ
stress
Authors: White Adrian J. , Traugott Martin O. , Swarbrick Richard E.
Published: November 2010

Leak-off tests (LOTs) or, preferably, extended leak-off tests (XLOTs), can be successfully used in minimum
in-situ
stress,
S
3
, estimations. Selecting a point on the leak-off graph that represents the best proxy for
S
3
can reduce inaccuracies in the use of LOTs as a means of determining
S
3
. If the testing procedure is well conducted and recorded, picking the leak-off pressure (LOP) or instantaneous shut-in pressure (ISIP) gives equally valid estimates of
S
3
. During testing, most of the pressure applied in the deduction of
S
3
is exerted by the static mud column, particularly in overpressured settings where higher drilling mud weights are used. Since the mud column contributes such a large proportion of the applied pressure, estimating
S
3
from tests conducted at greater depth means the observed small difference between LOP and ISIP has even less of an effect on the deduced
S
3
value. The data used in this study show that LOP closely matches ISIP when considering multiple cycle XLOTs. It can therefore be inferred that the LOP is the fracture re-opening pressure and hence
S
h
given that the assumptions made by the Kirsch equation for wellbore failure are upheld. This study also considers the implications for calculating the magnitude of
S
H
.
Quaternary lithology and shallow gas from high resolution gravity and seismic data in the central North Sea
Authors: Bauer Christian , Fichler Christine
Published: November 2010

High resolution marine gravity data and 3D post-stack seismic data from the central North Sea have been jointly interpreted. The accuracy of the gravity data allowed the detection of density contrasts related to a Quaternary sub-glacial melt-water channel, a shallow gas accumulation and a Tertiary gas chimney. The combination of gravity and seismic data is shown to particularly improve the detection of the shallow gas accumulation.

The interpretation included visual correlation of gravity images and seismic data performed in a seismic workstation environment, as well as 2.5D gravity modelling along selected seismic profiles. The successful application of this method on shallow targets requires a limited complexity of the shallow strata as well as targets defined by a distinct density contrast and a reasonable size. Data requirements include high-resolution bathymetric and free air gravity data. Bouguer gravity data, which are commonly used in exploration, cannot be used here as densities may vary within the uppermost layer below the sea bottom.
The effect of faults on the 3D connectivity of reservoir bodies: a case study from the East Pennine Coalfield, UK
Authors: Bailey W. R. , Manzocchi T. , Walsh J. J. , Keogh K. , Hodgetts D. , Rippon J. , Nell P. A. R. , Flint S. , Strand J. A.
Published: November 2010

The connectivity of reservoir bodies has been tested in unfaulted and variably faulted, high resolution 3D geocellular stratigraphic models (16 million cells in a 20 km × 20 km ×
c
. 600 m volume) from the East Pennine Coalfield, UK. These deterministic stratigraphic–structural models are underpinned by high density borehole and mineplan data. The stratigraphy extends from mid-Westphalian A to base Westphalian C and represents a low net:gross (0.03–0.27) coal-bearing, delta top/fluvial reservoir analogue. The models contain up to 1467 post-depositional normal faults with maximum displacements ranging from 1 m to 140 m. Using two sets of facies as net, the effect of fault size on inferred reservoir connectivity has been assessed for stratal intervals with different sedimentary architecture, interval net:gross and thickness.

Faults often disconnect reservoirs in thinner, lower net:gross intervals containing only laterally discontinuous, channelized bodies. By contrast, faults generally increase reservoir connectivity in thick, relatively high net:gross intervals containing laterally extensive, tabular reservoir bodies. The most significant factor for fault-related reservoir connectivity is the dimensionality and scale of reservoir bodies in relation to the displacement distribution along faults. Populations of small, sub-seismic, faults (<5 m throw) can reconnect reservoir bodies that are dissected by larger displacement, seismic resolvable, faults (>20 m throw).
Tectono-thermal evolution of the Qaidam Basin, China: evidence from Ro and apatite fission track data
Authors: Nansheng Qiu
Published: November 2010

In the Qaidam Basin, on the Northeastern Qinghai–Tibet Plateau, the thermal evolution of western and northern sub-basins was analysed using apatite fission track (AFT) data and vitrinite reflectance data from 27 wells. This study shows that thermal gradients decreased during the evolution of the basin, but there existed some differences in thermal evolution between the west and north of the basin, due to different tectonic movements. The thermal gradients in Paleocene–Miocene in the west and in Jurassic times in the north were more than 30°C km
−1
, exceeding present-day gradients. These thermal data can provide useful parameters for the study of the Qaidam Basin and Qinghai–Tibet Plateau. Palaeotemperature data are the critical parameter for hydrocarbon generation calculations. The results in this study provide a foundation for hydrocarbon generation history modelling and petroleum resources assessment in the Qaidam Basin.
How can we help ensure success of oil and gas field rehabilitation projects?
Authors: Heward Alan P. , Gluyas Jon G.
Published: November 2010

Oil field redevelopments or rehabilitation projects have become commonplace within the past decade. There are a number of reasons for this, not least that large old fields often contain significant quantities of remaining petroleum. Other major factors are that countries rich in petroleum but hitherto inaccessible to western oil companies have opened up their fields and as the world’s basins become thoroughly explored, field redevelopments look more attractive as the prospects for frontier exploration diminish.

Although now commonplace, field rehabilitations differ widely from redeveloping one’s own field in a familiar basin to entering a new country to work on an aging giant accumulation. The chance of success also varies widely, with modest redevelopments of one’s own fields commonly achieving success but bold forays into new countries and old fields often heralding commercial failure.

There are a number of actions that can be taken to improve the chance of success for any rehabilitation project. The selection of people forming the teams involved in evaluation and implementation requires considerable attention. If overseas, build on the know-how and experience of national staff. Every effort must be made to understand how the field performed and was worked in the past. The old well and production data need to be gathered, sorted, interpreted and made accessible to all in the project. The initial redevelopment targets must be modest, testing of hypotheses rigorous and acquisition of monitoring data on such pilot schemes extensive. ‘New technology’ may help but it is unlikely to be a panacea. Major financial outlay on, for example, new facilities should not be made until an understanding is achieved of how new wells and completions behave during production. Finally, success should be celebrated when success happens rather than celebrating proffered success before the project begins.
Innovative use of petrophysics in field rehabilitation, with examples from the Heather Field
Authors: Kay Simon , Cuddy Steve
Published: November 2010

The Heather oil field is located in the Northern North Sea and is operated by DNO Heather Limited. Oil is produced from sandstones of the Middle Jurassic Brent Group. Although approaching non-commercial flow rates, infill projects are under way which target unswept oil. At this late stage in field life, projects are typified by extracting as much new oil from the field as possible with minimal expenditure. These result in incomplete or degraded log data. This paper describes how the application of innovative techniques can replace data shortfalls, providing quality data without compromising budgetary constraints.

Four infill wells were drilled during 2000 and 2001. Innovative petrophysical techniques have been used to enhance the electric log data gathered. Fuzzy logic techniques have been applied to predict reservoir permeability and choose perforating intervals. Some sections of the highly deviated wells were necessarily logged in sliding mode and fuzzy logic was also used to repair the resulting degraded log curve data. Following the infill well programme, field production has increased from 5000 BBL oil per day (BOPD) to 7000 BOPD. This success was partly due to the better location of wells, particularly 2/5-H62Y, because of the improved reservoir model resulting from these petrophysical techniques.

The height above free-water level (HAFWL) was estimated across the Heather Field using the so-called FOIL function (bulk volume of water plotted as a function of HAFWL) (
Cuddy 1993
). The FOIL function has given valuable insights into free-water level variation across the Heather Field and has improved water saturation modelling. A method is presented in this paper for geosteering using the FOIL function.
Redevelopment of the Brighton Marine Field, Trinidad . . . the early days
Authors: Wallis Roderick J. , Ali Nazir , Barnes Peter , Khan Franklin , Whitfield Oliver
Published: November 2010

In October 1999, the Brighton Marine Block was awarded to Venture Production Company Trinidad Limited and Petrotrin, the Trinidadian National Oil Company, with Venture as operator.

The challenges to improved field recovery posed by such a complex field, with more than 50 years of production history, are many. The field has potential, but requires new interpretations and ideas based on both new and old datasets, a phased programme of rehabilitation and a long-term development plan that will generate immediate value without compromising long-term oil production.

Discovered in 1951, the Brighton Marine Field has produced almost 58×10
6
STB from an oil in place of over 500×10
6
STB. Production peaked at 14 000 BOPD in 1967 but had not exceeded 1000 BOPD since 1983.

Some 275, mostly deviated, wells were drilled into the field from 11 onshore pads and 9 offshore platforms. In the year since Venture assumed operations, production rose to nearly 2000 BOPD through field infrastructure rehabilitation, well work-overs and the implementation of new field management processes. In early 2001, the first new well proved the presence of a commercial quantity of petroleum in a hitherto undepleted part of the field.

It is very early in the rehabilitation process and much remains uncertain, but significant progress has been made in understanding the field and tapping its full potential. The field’s first 3D seismic survey, acquired in 1997, has provided a significant enhancement to the understanding of a structurally and stratigraphically complex field. The field compartmentalization and 50 years of production, have complicated the distribution of pressures, sweep and compaction. In order to mitigate risks, a phased strategy was implemented. This process focuses initially on the most straightforward, cost-effective opportunities. These redevelopments are designed to maximize data collection, test new models and help finance more extensive developments. Already, this approach is starting to yield results, although it is still early days.
Intracellular signaling pathways regulating net protein balance following diaphragm muscle denervation
Authors: Argadine Heather M. , Mantilla Carlos B. , Zhan Wen-Zhi , Sieck Gary C.
Published: November 2010

Unilateral denervation (DNV) of rat diaphragm muscle increases protein synthesis at 3 days after DNV (DNV-3D) and degradation at DNV-5D, such that net protein breakdown is evident by DNV-5D. On the basis of existing models of protein balance, we examined DNV-induced changes in Akt, AMP-activated protein kinase (AMPK), and ERK½ activation, which can lead to increased protein synthesis via mammalian target of rapamycin (mTOR)/p70S6 kinase (p70S6K), glycogen synthase kinase-3β (GSK3β), or eukaryotic initiation factor 4E (eIF4E), and increased protein degradation via forkhead box protein O (FoxO). Protein phosphorylation was measured using Western analyses through DNV-5D. Akt phosphorylation decreased at 1 h and 6 h after DNV compared with sham despite decreased AMPK phosphorylation. Both Akt and AMPK phosphorylation returned to sham levels by DNV-1D. Phosphorylation of their downstream effector mTOR (Ser2481) did not change at any time point after DNV, and phosphorylated p70S6K and eIF4E-binding protein 1 (4EBP1) increased only by DNV-5D. In contrast, ERK½ phosphorylation and its downstream effector eIF4E increased 1.7-fold at DNV-1D and phosphorylated GSK3β increased 1.5-fold at DNV-3D ( P < 0.05 for both comparisons). Thus, following DNV there are differential effects on protein synthetic pathways with preferential activation of GSK3β and eIF4E over p70S6K. FoxO1 nuclear translocation occurred by DNV-1D, consistent with its role in increasing expression of atrogenes necessary for subsequent ubiquitin-proteasome activation evident by DNV-5D. On the basis of our results, increased protein synthesis following DNV is associated with changes in ERK½-dependent pathways, but protein degradation results from downregulation of Akt and nuclear translocation of FoxO1. No single trigger is responsible for protein balance following DNV. Protein balance in skeletal muscle depends on multiple synthetic/degradation pathways that should be studied in concert.
Transmural differences in respiratory capacity across the rat left ventricle in health, aging, and streptozotocin-induced diabetes mellitus: evidence that mitochondrial dysfunction begins in the subepicardium
Authors: MacDonald J. R. , Oellermann M. , Rynbeck S. , Chang G. , Ruggiero K. , Cooper G. J. S. , Hickey A. J. R.
Published: November 2010

In diabetic cardiomyopathy, ventricular dysfunction occurs in the absence of hypertension or atherosclerosis and is accompanied by altered myocardial substrate utilization and depressed mitochondrial respiration. It is not known if mitochondrial function differs across the left ventricular (LV) wall in diabetes. In the healthy heart, the inner subendocardial region demonstrates higher rates of blood flow, oxygen consumption, and ATP turnover compared with the outer subepicardial region, but published transmural respirometric measurements have not demonstrated differences. We aim to measure mitochondrial function in Wistar rat LV to determine the effects of age, streptozotocin-diabetes, and LV layer. High-resolution respirometry measured indexes of respiration in saponin-skinned fibers dissected from the LV subendocardium and subepicardium of 3-mo-old rats after 1 mo of streptozotocin-induced diabetes and 4-mo-old rats following 2 mo of diabetes. Heart rate and heartbeat duration were measured under isoflurane-anesthesia using a fetal-Doppler, and transmission electron microscopy was employed to observe ultrastructural differences. Heart rate decreased with age and diabetes, whereas heartbeat duration increased with diabetes. While there were no transmural respirational differences in young healthy rat hearts, both myocardial layers showed a respiratory depression with age (30–40%). In 1-mo diabetic rat hearts only subepicardial respiration was depressed, whereas after 2 mo diabetes, respiration in subendocardial and subepicardial layers was depressed and showed elevated leak (state 2) respiration. These data provide evidence that mitochondrial dysfunction is first detectable in the subepicardium of diabetic rat LV, whereas there are measureable changes in LV mitochondria after only 4 mo of aging.
Antagonist action of progesterone at σ-receptors in the modulation of voltage-gated sodium channels
Authors: Johannessen Molly , Fontanilla Dominique , Mavlyutov Timur , Ruoho Arnold E. , Jackson Meyer B.
Published: November 2010

σ-Receptors are integral membrane proteins that have been implicated in a number of biological functions, many of which involve the modulation of ion channels. A wide range of synthetic ligands activate σ-receptors, but endogenous σ-receptor ligands have proven elusive. One endogenous ligand, dimethyltryptamine (DMT), has been shown to act as a σ-receptor agonist. Progesterone and other steroids bind σ-receptors, but the functional consequences of these interactions are unclear. Here we investigated progesterone binding to σ1- and σ2-receptors and evaluated its effect on σ-receptor-mediated modulation of voltage-gated Na+channels. Progesterone binds both σ-receptor subtypes in liver membranes with comparable affinities and blocks photolabeling of both subtypes in human embryonic kidney 293 cells that stably express the human cardiac Na+channel Nav1.5. Patch-clamp recording in this cell line tested Na+current modulation by the σ-receptor ligands ditolylguanidine, PB28, (+)SKF10047, and DMT. Progesterone inhibited the action of these ligands to varying degrees, and some of these actions were reduced by σ1-receptor knockdown with small interfering RNA. Progesterone inhibition of channel modulation by drugs was consistent with stronger antagonism of σ2-receptors. By contrast, progesterone inhibition of channel modulation by DMT was consistent with stronger antagonism of σ1-receptors. Progesterone binding to σ-receptors blocks σ-receptor-mediated modulation of a voltage-gated ion channel, and this novel membrane action of progesterone may be relevant to changes in brain and cardiovascular function during endocrine transitions.