bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
3D high-resolution digital models of outcrop analogue study sites to constrain reservoir model uncertainty: an example from Alport Castles, Derbyshire, UK
Authors: Pringle J. K. , Westerman A. R. , Clark J. D. , Drinkwater N. J. , Gardiner A. R. 
Published: October 2008

Advances in data capture and computer technology have made possible the collection of 3D high-resolution surface and subsurface digital geological data from outcrop analogues. This paper describes research to obtain the 3D distribution and internal sedimentary architecture of turbidite channels and associated sediments at a study site in the Peak District National Park, Derbyshire, UK. The 1D, 2D and 3D digital datasets included Total Station survey, terrestrial photogrammetry and remote sensing, sedimentary logs and a Ground Penetrating Radar (GPR) dataset. A grid of 2D GPR profiles was acquired behind a cliff outcrop; electromagnetic reflection events correlated with cliff face sedimentary horizons logged by Vertical Radar Profiling. All data were combined into a Digital Solid Model (DSM) dataset of the site within reservoir modelling software.
The DSM was analysed to extract 3D architectural geometries for petroleum reservoir models. A deterministic base model was created using all information, along with a suite of heterogeneous turbidite reservoir models, using 1D, 2D or 3D information. The model suite shows significant variation from the deterministic model. Models built from 2D information underestimated connectivity and the continuity of geobodies, but overestimated channel sinuosity. Advantages of using 3D digital outcrop analogue data for 3D reservoir models are detailed.
Thermal history and oil charge on the UK Atlantic margin
Authors: Parnell J. , Green P.F. , Watt G. , Middleton D. 
Published: October 2008

Integrated apatite fission track analysis and vitrinite reflectance data show that well 204/19-1 in the West of Shetland region, UK Atlantic margin, has experienced only limited additional burial beyond present-day depths. Uplift and cooling to present-day levels probably occurred during late Cenozoic (Eocene to Miocene) basin inversion. Fluid inclusion data indicate that Paleocene–Eocene sandstones have experienced temperatures much higher than can be explained by burial alone. Temperatures up to 200±°C indicate the passage of hot fluid through Cenozoic sandstones, which by-passed the pre-Cenozoic section in this and other wells. The hot fluid event must have been of very brief duration (up to 100 years) to show no record in the fission track and reflectance data, implying that the fluids migrated through fracture systems.
Oil inclusions in the Cretaceous of well 204/19-1 have a chemistry that suggests derivation from a Kimmeridgian-aged source rock. They occur in cements that show no evidence for the hot fluid event and it is concluded that the cements pre-date the event. Oil inclusions in Cenozoic sandstones have a heavy, degraded character and were trapped at high temperature, suggesting that degradation was related to the hot fluid event. Present-day oils in the West of Shetland region are mixtures, which could reflect components from the two charges distinguished by the integrated thermal and geochemical histories. The inference of fracture-bound flow is consistent with existing models of overpressure development and hydrofracturing.
Reserve growth in oil fields of the North Sea
Authors: Klett T. R. , Gautier Donald L. 
Published: October 2008

The assessment of petroleum resources of the North Sea, as well as other areas of the world, requires a viable means to forecast the amount of growth of reserve estimates (reserve growth) for discovered fields and to predict the potential fully developed sizes of undiscovered fields. This study investigates the utility of North Sea oil field data to construct reserve-growth models. Oil fields of the North Sea provide an excellent dataset in which to examine the mechanisms, characteristics, rates and quantities of reserve growth because of the high level of capital investments, implementation of sophisticated technologies and careful data collection. Additionally, these field data are well reported and available publicly.
Increases in successive annual estimates of recoverable crude oil volumes indicate that oil fields in the North Sea, collectively and in each country, experience reserve growth. Specific patterns of reserve growth are observed among countries and primary producing reservoir-rock types. Since 1985, Norwegian oil fields had the greatest volume increase; Danish oil fields increased by the greatest percentage relative to 1985 estimates; and British oil fields experienced an increase in recoverable oil estimates for the first ten years since 1985, followed by a slight reduction. Fields producing primarily from clastic reservoirs account for the majority of the estimated recoverable oil and, therefore, these fields had the largest volumetric increase. Fields producing primarily from chalk (limestone) reservoirs increased by a greater percentage relative to 1985 estimates than did fields producing primarily from clastic reservoirs. Additionally, the largest oil fields had the greatest volumetric increases. Although different reserve-growth patterns are observed among oil fields located in different countries, the small number of fields in Denmark precludes construction of reserve-growth models for that country. However, differences in reserve-growth patterns among oil fields that produce from primarily clastic and primarily chalk reservoirs, in addition to a greater number of fields in each of the two categories, allow separate reserve-growth models to be constructed based on reservoir-rock type.
Reserve-growth models referenced to the date of discovery and to the date of first production may be constructed from North Sea field data. Years since discovery or years since first production are used as surrogates for, or measures of, field-development effort that is applied to promote reserve growth. Better estimates of recoverable oil are made as fields are developed. Because much of the field development occurs some time later than the field discovery date, reserve-growth models referenced to the date of first production may provide a more appropriate measure of development than does date of discovery.
Characterization of deeply buried heterolithic tidal reservoirs in the Smørbukk Field using inverted post-stack seismic acoustic impedance
Authors: Klefstad L. , Kvarsvik S. , Ringås J. E. , Stene J. J. , Sundsby O. 
Published: October 2008

Deeply buried reservoirs in Smørbukk Field play an important role in oil production from the Halten Terrace hydrocarbon province (Mid-Norwegian shelf). These heterolithic reservoir sandstones are sedimentary systems for which estimation of reservoir properties is challenging. The main problem is to derive realistic models of the lateral changes of porosities and permeabilities in the inter-well space. There is a very significant upside potential in producible reserves if infill production wells can be placed and completed in an optimal position with respect to reservoir quality.
In this paper reservoir characterization work, based on good quality seismic data, has been performed in order to predict porosity, net: gross ratio and permeability both qualitatively and quantitatively supported by reliable geological models. Essentially, Acoustic Impedance (AI) is correlated to porosity and inverted seismic data have been used to predict reservoir properties. Two different porosity modelling methods in the Tilje Formation are used: (1) by means of simple regression; (2) using geostatistical methods.
Lateral changes in porosity follow a pattern that is sedimentologically plausible. A geostatistical workflow resulted in porosity maps that take into account both lack of vertical resolution in seismic data and poor lateral resolution in well data. This is considered to be the most optimal method for predicting geologically acceptable reservoir properties, because uncertainties in porosity modelling are measured. Porosity maps were used to update the reservoir simulation model and adjust targets for infill wells in the Smørbukk Field. Results were tested in two wells drilled after utilizing the seismic AI and showed an excellent match.
A regional chemostratigraphically-defined correlation framework for the late Triassic TAG-I Formation in Blocks 402 and 405a, Algeria
Authors: Ratcliffe K. T. , Martin J. , Pearce T. J. , Hughes A. D. , Lawton D. E. , Wray D. S. , Bessa F. 
Published: October 2008

The Triassic Argilo-Gréseux Inférieur Formation (TAG-I) is one of the principal hydrocarbon reservoirs in the Berkine Basin of Algeria. Sedimentological studies have shown that it exhibits marked spatial and temporal facies variations on both a local field scale and a regional basinal scale. This variability, combined with a lack of diagnostic flora and fauna, makes regional correlation within the unit difficult. In turn, the lack of a consistent regional stratigraphic framework hampers the comparison of the various correlation schemes devised by operators in the basin.
Contrasting the TAG-I in Blocks 402 and 405a exemplifies the problems encountered when attempting regionally to define a correlation framework for the interval. Between these two blocks, a distance of approximately 200 km, there are marked changes in the style of deposition from sand-dominated, proximal fluvial systems in the SW (Block 405a, MLN, MLC, KMD and MLNW fields) to a more distal, more clay-prone system in the NE (Block 402, ROD/BRSE/BSFN, SFNE and BSF fields). A chemostratigraphic study of the TAG-I in these two blocks has allowed a four-fold correlation framework to be defined, where each chemostratigraphic package has distinctive geochemical features. Chemostratigraphic Package 10, the oldest unit, lies above the Hercynian Unconformity, but beneath a geochemically identifiable hiatal surface. Chemostratigraphic Package 20 lies above the hiatal surface but is separated from the overlying packages by a mineralogical change identifiable in both claystone and sandstone geochemistry. Chemostratigraphic Packages 30 and 40 are chemically somewhat similar, but are separated by a regional event interpreted as a period of dolocrete and lacustrine development. By combining the geochemical differentiation of the units and recognition of their stratal boundaries, it is possible to define a correlation for the TAG-I between Blocks 402 and 405a.
The proposed correlation between the two blocks suggests that the northern parts of Block 405a may have been occupied by a spur or subsidiary channel from the main SW–NE-trending fluvial system, resulting in one of the chemically defined packages being demonstrably absent in the MLNW, MLN, KMD and MLC fields when compared with the other areas of the study.
An atypical early mature oil in Block 35/1, Norwegian North Sea – hypersaline, carbonate Jurassic environment?
Authors: Ohm S. E. , Beeley H. , Karlsen D. A. , Hall P. B. , Foss A. 
Published: October 2008

Block 35/1 with the dry Sturlason structure, is located on the northernmost part of the Marflo Ridge in the Norwegian part of the Northern North Sea. It is separated by deep faults from the Sogn Graben to the east and the Marulk Basin to the west. The 35/1-1 well proved only minor shows of gas and oil in the well.
The Sturlason structure comprises a series of upthrown fault blocks in a structurally complex area. The well-established Brent Formation carrier and reservoir sandstone has shaled out this far north and the stratigraphically deeper Lower Jurassic Statfjord Formation and Triassic Lunde Formation sandstones were, in the exploration model, suggested as both carrier beds and reservoirs. The prolific Upper Jurassic Draupne (Type II organic matter, OM) and Heather (Type II/III OM) Formation source rocks were, based on seismic data, interpreted to be absent or thin over the prospect, thus implying lateral migration for filling the structure with petroleum. Structural back-stripping suggests that part of Block 35/1 was sub-aerially exposed as an island during deposition of the Upper Jurassic source rocks. This may have impacted the quality and nature of the fringing organic material due to a more oxic environment and a greater influx of Type III organic matter.

The geochemical analyses were hampered by contamination from the use of oil-based mud (C
13–23
range hydrocarbons) while drilling. Despite this, traces of true indigenous C
4–10
and C
25+
range hydrocarbon are demonstrated. These results suggest presence of an evaporative condensate and heavy oil fraction originating from a source rock related to a hypersaline carbonate depositional environment.

A buoyancy-driven fluid flow study, without taking faults into account, shows the difficulty in charging the prospect and clearly suggests the presence of sealing faults. The latter are also substantiated by a separate fault-seal analysis. Traps in flanking areas could, however, receive petroleum. Gas is also interpreted to be present in shallower sediments over the eastern flank of the Sturlason structure.
Interaction of the Zagros Fold–Thrust Belt and the Arabian-type, deep-seated folds in the Abadan Plain and the Dezful Embayment,SW Iran
Authors: Fard Iraj Abdollahie , Braathen Alvar , Mokhtari Mohamad , Alavi Seyed Ahmad 
Published: October 2008

The Dezful Embayment and Abadan Plain (SW Iran) contain major parts of the remaining Iranian oil reserves. These oil provinces are characterized by two types of structural closure: very gentle N–S- to NE–SW-trending basement-cored anticlines (Arabian-type highs) in the SE; and open to tight, NW–SE-trending thrust-related folds in the NE (Zagros Fold–Thrust Belt; ZFTB). Most deep-seated anticlines are upright and symmetrical in Cretaceous and older units. In some cases they reveal steep faults in their core which, in the light of regional observations, suggest that the basement is involved in the faulting. Untested plays around these anticlines include reefal build-ups, debris flows, truncated sedimentary sections and onlapping clastic units.
The ZFTB shows a classic structural style, with overall shortening reflected in thrust displacement declining from the Dezful Embayment towards the frontal zone in the Abadan Plain. The Early Cambrian Hormuz Salt represents the fundamental sole for the fold–thrust belt and locates major fault-propagation folds in the southwestern Dezful Embayment. These folds represent the main petroleum target of the area. Another important unit is the Mid-Miocene Gachsaran Formation. This detachment reveals both in-sequence and out-of-sequence thrusting. Interaction of deep-seated anticlines and fold–thrust structures results in thrust imbrications and formation of duplexes within the Gachsaran Formation when thrusts abut deep-seated anticlines. Above the crest of the anticlines, thrusts are forced up-section into syn-tectonic deposits, whereas the forelimb reveals out-of-the-syncline thrusts. Several petroleum plays are identified in such zones of structural interaction, including anticlines above buttress-related duplexes, out-of-sequence imbricate thrust fans with associated folds above major anticlines, truncation of footwall layers below potentially sealing thrusts, and sub-thrust anticlines.
Sensitivity of the impact of geological uncertainty on production from faulted and unfaulted shallow-marine oil reservoirs: objectives and methods
Authors: Manzocchi T. , Carter J. N. , Skorstad A. , Fjellvoll B. , Stephen K. D. , Howell J. A. , Matthews J. D. , Walsh J. J. , Nepveu M. , Bos C. , Cole J. , Egberts P. , Flint S. , Hern C. , Holden L. , Hovland H. , Jackson H. , Kolbjørnsen O. , MacDonald A. , Nell P. A. R. , Onyeagoro K. , Strand J. , Syversveen A. R. , Tchistiakov A. , Yang C. , Yielding G. , Zimmerman R. W. 
Published: October 2008

Estimates of recovery from oil fields are often found to be significantly in error, and the multidisciplinary SAIGUP modelling project has focused on the problem by assessing the influence of geological factors on production in a large suite of synthetic shallow-marine reservoir models. Over 400 progradational shallow-marine reservoirs, ranging from comparatively simple, parallel, wave-dominated shorelines through to laterally heterogeneous, lobate, river-dominated systems with abundant low-angle clinoforms, were generated as a function of sedimentological input conditioned to natural data. These sedimentological models were combined with structural models sharing a common overall form but consisting of three different fault systems with variable fault density and fault permeability characteristics and a common unfaulted end-member. Different sets of relative permeability functions applied on a facies-by-facies basis were calculated as a function of different lamina-scale properties and upscaling algorithms to establish the uncertainty in production introduced through the upscaling process. Different fault-related upscaling assumptions were also included in some models. A waterflood production mechanism was simulated using up to five different sets of well locations, resulting in simulated production behaviour for over 35 000 full-field reservoir models. The model reservoirs are typical of many North Sea examples, with total production ranging from
c
. 15×10
6
m
3
to 35×10
6
m
3
, and recovery factors of between 30% and 55%. A variety of analytical methods were applied. Formal statistical methods quantified the relative influences of individual input parameters and parameter combinations on production measures. Various measures of reservoir heterogeneity were tested for their ability to discriminate reservoir performance. This paper gives a summary of the modelling and analyses described in more detail in the remainder of this thematic set of papers.
Pressure regression, fluid drainage and a hydrodynamically controlled fluid contact in the North Sea, Lower Cretaceous, Britannia Sandstone Formation
Authors: O'Connor Stephen A. , Swarbrick Richard E. 
Published: October 2008

The Lower Cretaceous Britannia Sandstone Formation is located below overpressured Sola Formation shales (
c
. 2800 psi overpressure) and above Jurassic reservoirs (up to 5700 psi overpressure) and represents a pressure regression, recording overpressure values ranging from approximately 100 psi in Block 15/30 (in the extensional Outer Moray Firth/Central North Sea basin) up to a maximum of approximately 1600 psi in Block 22/4. The Britannia Sandstone has an anomalously low overpressure when compared with deeper Cretaceous (Valhall) and Jurassic reservoir overpressures locally, and further afield in the Central North Sea at similar depths.

The pore pressures in the Sola Formation shales have been estimated using conventional porosity/sonic-based prediction methods, indicating strong overpressure disequilibrium between the Sola Formation shales and the Britannia Sandstones, both in the Britannia Field area and in the laterally age-equivalent sands to the west referred to as the Kopervik Fairway (the Aptian sands of the South Halibut Basin, forming the reservoirs of the Blake, Captain and Goldeneye fields).
Burial curve modelling indicates that it is likely that the Sola Formation shales have overpressured for the last 4 Ma, and likely much longer, suggesting an early history of pressure build up (now preserved in the Sola Formation shales and deeper, Jurassic reservoirs and associated sediments). The adjacent Britannia Sandstone Formation therefore lost fluid and pressure due to local availability of a fluid conduit. Resulting active fluid flow, driven by overpressure differences in the Britannia Sandstone Formation, has created a hydrodynamically tilted hydrocarbon–water contact with lateral flow from east to west. Well evidence indicates vertical flow from shallower reservoirs into the stratigraphically deeper, main Britannia reservoir. The fluid escape could be either laterally via the Kopervik Fairway and/or vertically through the Upper Cretaceous Chalk facilitated by fractures/faulting.
Enhanced depositional and AVO models for lithologically complex sandstones in the Santos Basin, offshore Brazil
Authors: Klarner Sabine , Ujetz Bernhardt , Fontana Rogério L. 
Published: October 2008

While exploring for hydrocarbons in rift-related basins, volcanic and volcaniclastic rocks and their erosional products are commonly encountered lithologies. At the reservoir level, the presence of rock types derived from volcanism or affected by post-volcanic re-deposition leads to highly varied complex lithologies with wide ranges of inherent rock properties.
In the Santos Basin, a number of exploration wells have encountered basalts emplaced along the basin hinge line that have controlled the sedimentation and basin geometry. The main reservoir units of the basin consist of complex Upper Cretaceous sandstones deposited during periods of active volcanism. For one of the main exploration targets, the Senonian Ilhabela Formation, integrated geological and geophysical interpretation of recently acquired seismic and well data has led to a refined sedimentological model, an enhanced AVO model as well as a deeper understanding of the petroleum system. The encountered sandstones are of shallow-marine and deltaic origin, with local occurrence of mafic volcanic and subvolcanic rocks. Dependent on the presence of volcanic rocks in the vicinity of the particular reservoir, two different types of sandstones with different AVO characteristics have been identified. The presence of volcanic rocks may be interpreted from seismic data by their distinct geometry, usually high amplitudes and unique AVO behaviour, expressed as a strengthening of positive amplitudes with increasing offset.