bluuebunny/crossref_metadata_2025 huggingface dataset:
The Victory gas field, West of Shetland
Authors: GOODCHILD M. W. , HENRY K. L. , HINKLEY R. J. , IMBUS S. W.
Published: April 2010

The Victory gas field is located 48 km northwest of the Shetland Isles, in UKCS Block 207/la. The structure was first drilled in 1977, the discovery well 207/1-3 encountering 224 ft (68 m) of gas-charged Lower Cretaceous sandstone at a subsea depth of 4144 ft (1263 m). No gas–liquid contact was recorded in the well. Five wells have been drilled on the Victory trend to date with the most recent, 207/la-5, being drilled in 1996. The Victory Field was originally mapped with 2D seismic data as a structural high associated with a rotated fault block. In 1996, 3D seismic data were acquired over the area as part of a Shell-operated group-shoot and the improvements in resolution and data quality have prompted a re-evaluation of the field. The 3D seismic data have demonstrated that the Rona Ridge and the linked West Shetland Basin in this area have undergone a complex geological history with multiple phases of Cretaceous tectonism. The structural elements that affect trap configuration and reservoir sand distribution are related to faulting which follows both a NE–SW Caledonian trend and an offsetting NW to SE fault trend. The reservoir is of Early Cretaceous (Late Aptian–Late Albian) age and comprises shallow to marginal marine sandstones and conglomerates overlying Precambrian basement. Reservoir quality is consistently high. Geochemical analyses of both gas and oils encountered within the Victory field area have been undertaken and tied both to basin-scale modelling of the petroleum system and structural mapping at a field-scale. These studies demonstrate the complex, multi-phase charge and alteration history of the trapped hydrocarbons of the Victory Field.
The Trent Gas Field: correlation and reservoir quality within a complex Carboniferous stratigraphy
Authors: O’MARA P. T. , MERRYWEATHER M. , STOCKWELL M. , BOWLER M. M.
Published: April 2010

The Trent Field gas accumulation in the UKCS (United Kingdom Continental Shelf) Southern Gas Basin is reservoired in Carboniferous age sediments. It is contained within a NW–SE trending base Permian structural feature that straddles Blocks 43/24a, 43/23 and 43/25. The proven reserves within the core area lie solely within the 43/24a block. Field appraisal and development encountered three main areas of complexity: structure, reservoir continuity and reservoir property variations.

The 20 km long base Permian feature is controlled by NW–SE trending post-Rotliegendes reverse faults which produced a positive inversion. Antithetic faults to these reverse faults also occur within the structure. A second WSW–ENE normal fault trend comparmentalizes the field, and is also thought to have influenced sedimentation during Carboniferous times. Similar fault-influenced deposition is documented at equivalent times in the UK onshore. Ultimately this structural complexity controls the Carboniferous subcrop, which is seen to increase in age from late to early Westphalian A, in a southeasterly direction, although dramatic changes can occur on a more local scale in some fault compartments.

The Trent Field accumulation is contained within an interval ranging in age from Marsdenian to early Westphalian A. It encompasses a number of facies associations in delta top and lower delta plain environments, which vary rapidly both vertically and laterally. Reservoir facies include incised valley-fills, transgressive reworked sandstones and distributary channels, which vary markedly in their lateral extent. Reservoir quality of these facies ranges from very poor to excellent and is controlled primarily by the depositional environment in which grain size and sediment maturity are the most important factors.
Controls on Late Jurassic, subtle sand distribution in the Tampen Spur area, Northern North Sea
Authors: DAWERS N. H. , BERGE A. M. , HÄGER K.-O. , PUIGDEFABREGAS C. , UNDERHILL J. R.
Published: April 2010

The role of fault growth and linkage is an important, but poorly understood, factor in controlling the distribution of sediments within extensional settings. Tectonostratigraphic analysis of the Statfjord East fault system, located in the East Shetland Basin of the Northern North Sea, demonstrates the importance of Late Jurassic normal faulting in controlling the nature of subtle, hanging wall traps. Wells in Norwegian Block 34/7 have penetrated prospective sandstone reservoirs that correlate with several thin, but seismically resolvable, units within syn-rift sediments of the Statfjord East hanging wall. Detailed 3D seismic interpretation and mapping of amplitude anomalies in Block 34/7 and the adjacent part of Block 33/9 reveal a number of spatially discontinuous stratigraphic units within the Late Jurassic, syn-rift Draupne Formation. These depositional units are spatially related to sub-basins, which are controlled by interaction and linkage of several en echelon fault segments. The main control on the distribution of local depocentres is the along-strike displacement variation associated with fault propagation by segment linkage. A close association between sandstone occurrence and structural position, suggests a model in which shoreline migration is controlled by the dynamics of fault lengthening through time.
Downthrown closures of the Outer Moray Firth
Authors: MOSELEY B. A.
Published: April 2010

In the Outer Moray Firth area of the UK Continental Shelf, some 3 × 10
9
BBL of recoverable hydrocarbons have been discovered. The reservoir rocks are primarily shallow marine (Piper) and deep marine (Claymore) sands of Late Jurassic age, with subordinate amounts of hydrocarbons contained in Lower Cretaceous sandstones. The major fields include Piper, Scott, Claymore and Tartan. Whilst these are principally classical tilted fault block footwall traps, all except Piper have elements of downthrown, hanging wall trapping that add significantly to the reserve base. Several other fields and discoveries, including Scapa, Saltire, Perth, and Lowlander are entirely dependent upon downthrown fault closure.

A number of exploration wells drilled on valid downthrown terraces have, however, proved dry, apparently a result of lateral fault seal failure. An examination of the success and failure cases suggests that the critical factors controlling the trap integrity in this area are the geology and geometry of the sediments in the footwall, the timing of fault movement and the nature of the depositional system in the hanging wall. These appear to be more important than the more commonly used shale smear or gouge criteria. Consideration of these factors has allowed the construction of a ranking system for downthrown Mesozoic prospects.
The capabilities and challenges of the seismic method in chalk exploration
Authors: ANDERSON J. K.
Published: April 2010

The success of seismic methods to detect and predict porosity within the chalk fields of the Norwegian North Sea, coupled with the awareness that chalk can behave as both reservoir and seal, has led to the deliberate search for stratigraphically trapped hydrocarbons within the chalk. This effort has relied on seismic methods, such as post-stack inversion and amplitude versus offset (AVO) techniques, to identify porous reworked chalk zones isolated within low porosity pelagic chalk. The excellent conditions for seismic acquisition and processing, slowly varying regional geology, and high correlation between porosity and seismic velocities and density produce reliable porosity predictions far from well control for all inversion techniques. However, the high exploration failure rate for stratigraphic tests demonstrates that migration and seal risk is higher in chalk stratigraphic prospects, and some method of predicting hydrocarbon presence is beneficial. Analysis of available velocity measurements demonstrates that porosity and fluid variations in chalk can be modelled best with the upper bound of
Hashin and Shtrikmann (1963)
, modified with the critical porosity of
Nur (1992)
. This model leads to the conclusion that chalk velocities are sensitive to pore fluid and that hydrocarbon effects may be observable on seismic data. Unfortunately, hydrocarbon effects overprint the larger porosity effects, making resolution of the hydrocarbons signal extremely difficult in practice. An exploration case study demonstrates that the current inability to distinguish the effect of hydrocarbons from that of porosity, in the presence of noise and other complicating factors, seriously limits the ability of seismic methods to directly detect hydrocarbons under normal exploration conditions.
Exploration and appraisal of the South Arne Field, Danish North Sea
Authors: MACKERTICH D. S. , GOULDING D. R. G.
Published: April 2010

The South Arne Field lies in the Danish sector of the North Sea Basin 250 km WNW of Esbjerg on the Danish mainland. It is a chalk field 12 km by 3 km. The field was initially discovered in 1969 by the I-1 well which found a thin Maastrichtian Tor Formation producing up to 4040 BOPD upon test. The second well on the field (Baron-2) was drilled over 20 years later on the southwestern flank. The aim of this well, in addition to targeting deeper Jurassic prospectivity, was to test the concept that the chalk reservoir thickened off-structure. This well encountered no productive chalk reservoir and the prognosed Jurassic reservoir was not reached. Following a change of operator in 1994, the Rigs-1 well was drilled in the northern part of the field where the interpreted structure was most complex. The well was located on 2D seismic data towards the middle of what was interpreted to be a gas cloud. This well encountered a much thicker chalk reservoir sequence than had previously been drilled on the field. Following the acquisition of 3D seismic data and an intensive, integrated geological and geophysical work programme, an appraisal well (Rigs-2) and a down-dip sidetrack were planned in an area outside the gas cloud where the reservoir was predicted to be of high quality. These appraisal wells were very successful in their objectives and proved a stratigraphic element to the hydrocarbon trapping mechanism. The field development plan envisages the extensive use of horizontal wells and first oil is currently scheduled for mid 1999. Reserves are presently estimated to be 89 × 10
6
BBL oil, and 200 × 10
9
SCF of associated gas.
A subsurface perspective on ETAP – an integrated development of seven Central North Sea fields
Authors: POOLER J. , AMORY M.
Published: April 2010

In December 1995 the UK Government gave approval to develop the Eastern Trough Area Project (ETAP) – a major new project consisting of the integrated development of seven Central North Sea fields. During the development phase BP will operate four fields (Marnock, Machar, Mungo and Monan) and Shell will operate three fields (Heron, Egret and Skua). On commencement of production in 1998 BP will act as operator of the overall facilities on behalf of the seven co-venturers (BP, Shell, Esso, Agip, MOC Exploration, Murphy and Total).

The reservoir architecture, conditions and fluids pose some unique challenges for the project which represents the single largest North Sea development for ten years. The challenges include:

downhole sand control in high pressure/high temperature (HP/HT) horizontal wells;

management of uncertainty in forecasting target depths in diapir wells;

management of uncertainty in long term performance of fractured chalk under waterflood;

downhole salt/scale management under HP/HT conditions;

management of uncertainty in long term productivity from Skagerrak reservoirs; and

well engineering in HP/HT conditions.

This paper gives a brief overview of the challenges that ETAP is facing during development of these reservoirs and outlines how these will be addressed during the early field development stage.
The Elgin and Franklin fields: UK Blocks 22/30c, 22/30b and 29/5b
Authors: LASOCKI J. , GUEMENE J. M. , HEDAYATI A. , LEGORJUS C. , PAGE W. M.
Published: April 2010

The Elgin and Franklin fields are high pressure/high temperature (HP/HT) (1100 bars, 190°C) gas condensate accumulations lying in the southern Central Graben in UK Blocks 22/30c, 22/30b and 29/5b. The Elgin Field comprises a complex faulted anticlinal structure and the Franklin Field, a tilted fault block. The principal reservoir comprises highly bioturbated, very fine-grained, shallow marine sandstones of the Upper Jurassic Fulmar Formation. A significant amount of secondary porosity (up to half the observed porosity) developed in these deep fields (>5 km subsea) which together with the extreme overpressure (500 bars excess) and stable grain mineralogy resulted in preservation of high quality reservoirs. The hydrocarbons have been sourced from the Upper and Middle Jurassic shales and coals and are sealed by the Upper Jurassic shales and Lower Cretaceous marls. The gas condensates are liquid rich with condensate yields of up to 1345 g Sm
−3
in Elgin and 695 g Sm
−3
in Franklin.

The fields, discovered in 1985 (Franklin) and 1991 (Elgin), are currently being developed with production start-up scheduled for 2000. Recoverable reserves are estimated to be around 25 × 10
9
m
3
(890 × 10
9
SCF) gas and 29 × 10
6
tonnes (245 × 10
6
BBL) condensate for Elgin and 23 × 10
9
m
3
(820 × 10
9
SCF) gas and 15 × 10
6
tonnes (120 × 10
6
BBL) for Franklin.
The Brent Field: improving subsurface characterization for late field life management
Authors: JAMES S. , PRONK D. , ABBOTS F. , WARD V. , VAN DIERENDONCK A. , STEVENS D.
Published: April 2010

The Brent Field was discovered in 1971 and is now a mature asset. In order to increase oil and gas ultimate recovery, the field commenced depressurization in 1997. The re-development of the field has been underpinned by extensive static and dynamic modelling studies. Developments in geological computing and the numerical processing power of reservoir simulation platforms have significantly improved the quality of the Brent Field static and dynamic models. These models have been used for a range of studies including gas cap volumetrics, by-passed oil investigations and to select the appropriate reservoir access well technology. The constant optimization of hydrocarbon recovery from the structurally and stratigraphically complex reservoir sequence of the field requires, however, that the static reservoir models are continually revised as new data become available and existing data is re-interpreted. A new 3D seismic survey was acquired in 1995. Interpretation commenced in mid-1996 and immediately showed that significantly improved subsurface resolution had been obtained. This initiated the next major iteration of static reservoir modelling which will ultimately result in the next generation of static and dynamic reservoir models. As the first results of this work have become available, the reservoir modelling effort has focused on some of the most complex areas of the field.
Application of 3D visualization and VSP for horizontal well positioning – 9/13a-Nl case history, Nevis Field, UKCS
Authors: DICKSON A. J. , BINGHAM G. C. , STYLIANIDES G. C. , THOMPSON H. W. A. , WAY N. A.
Published: April 2010

The Nevis Field, operated by Mobil North Sea Limited, came on stream in September 1996. This was achieved by completion of an existing vertical well in the Triassic and the drilling and completion of a horizontal well in the Middle Jurassic Beryl Formation. Horizontal wells are necessary for the economic development of the field. However, these wells are high risk because of the relatively thin and faulted reservoir interval. A multi-disciplinary team was formed to manage the risk of the crucial first horizontal well.

3D visualization was used to allow all disciplines the opportunity to understand the structure and difficulties associated with the well. A pilot well was planned to maximize the chance of penetrating the oil-water contact. A wide range of possible horizontal well trajectories, dependent on the results of the pilot, were constructed interactively in 3D. Using an iterative process, a well path was engineered that catered for the range of outcomes.

An imaging vertical seismic profile (VSP) was acquired in the pilot well to help optimize the location of the final horizontal section. Thorough planning resulted in faults not apparent in the 3D dataset being identified on the VSP. Detailed structure maps were created based on the faults and bed dips interpreted from the VSP and fault trends observed from the 3D seismic data. The well design work in 3D meant that the required horizontal well trajectory could be drilled. The final horizontal section proved 610 m (2000 ft) of oil bearing section. The successful drilling of the well is considered to be largely as a result of extensive multi-disciplinary contingency planning.
Integrating sequence stratigraphy in field development and reservoir management – the Telford Field
Authors: SYMS R. M. , SAVORY D. F. , WARD C. J. , EBDON C. C. , GRIFFIN A.
Published: April 2010

The Telford Field is located in Quad 15 of the UK North Sea and is reservoired in Late Jurassic shallow marine sandstones of the Piper Formation. The field has been developed with three producer–injector pairs and came on stream at the end of 1996 following a twelve month development programme.

In terms of sequence stratigraphy, the Upper Jurassic Piper Formation reservoir occurs within sequences LJ2 and LJ3 of the Amoco regional framework. In the Telford Field these sequences include a wide variety of facies representing delta-front to delta-margin settings. As a result the reservoir section displays distinct vertical and lateral heterogeneities.

Prior to development a high resolution sequence framework was established comprising seven genetic sequences bounded by maximum flooding surfaces. This framework formed the basis of the reservoir zonation and was integral to the success of the development wells.

The sequence based reservoir zonation was refined following the development drilling into 17 zones which were further enhanced with the aid of
k/φ
plots to form a total of 22 flow units. When applied in the reservoir simulation the sequence stratigraphic model allowed predictions of lateral continuity and extent of transmissibility barriers and baffles. Consequently, waterflood performance could be assessed and a perforation strategy adopted which would delay early water breakthrough whilst optimizing production and ultimate recovery.

By attempting to understand the bounding surfaces of the zones and their internal flow characteristics, we can go some way to predicting reservoir architecture and connectivity and, in theory, reservoir performance.
Fulmar: a mature field revisited
Authors: SPAAK P. , ALMOND J. , SALAHUDIN S. , MOHD SALLEH Z. , TOSUN O.
Published: April 2010

The original STOIIP of the Fulmar Field is currently estimated as 853 × 10
6
STB and it is considered that approximately 540 × 10
6
STB of oil has so far been produced, representing 63.4% of the original reserves. This high recovery factor coupled with an increasingly high water-cut (currently averaging 90%) suggests that the end of field life is drawing close. Prior to making an abandonment decision however it was considered prudent to review and update both the geological and dynamic reservoir models in order to ensure that the full field potential has been realized before making provisions for abandonment. In this context, the depositional model and stratigraphic architecture of the Upper Jurassic Fulmar Sands have been reviewed. Two geological models have been considered: (1) the preexisting model; and (2) an alternative model, which reflects continuing uncertainties in the field’s stratigraphic architecture.
Reservoir characterization in the Captain Field: integration of horizontal and vertical well data
Authors: ROSE P. T. S.
Published: April 2010

The Captain Field lies in UKCS Block 13/22. It is a large viscous oil field with an excellent quality Lower Cretaceous sandstone reservoir. Development of this high viscosity crude (88 cp at the
in situ
temperature, 87°F) in the offshore environment was possible only after the development of reliable horizontal drilling technology, combined with high volume down-hole electric pumps, and the ability to run long pre-packed sand control screens. As the first development of this type within Texaco, the development decision was helped by the extremely favourable reservoir conditions present in the Captain Field.

The Captain reservoir is encountered directly beneath the chalk and consists of Late Aptian aged turbidite sandstones, with high porosity (av. 31%) and permeability (av. 7 D). The sandstones were deposited on the feather edge of a large turbidite fan system derived from the East Shetland Platform to the north and which thins onto the Captain Ridge. The reservoir sequence consists of two principal sand bodies, the Upper and Lower Captain Sandstones with contrasting reservoir geometry. The Upper Captain Sandstone is developed in a continuous sheet that systematically thins and pinches out to the southeast whereas the Lower Captain Sandstone is concentrated in a sand fairway, interpreted to be a back-filled submarine canyon cutting across the Captain ridge. Core description show the sandstones to be predominantly massive suspension fall out sediments (S3 deposits,
Lowe 1982
) with rare intra-reservoir claystones.

In this paper the reservoir geometry and sedimentology of the Captain Sandstone Member is described with particular attention being drawn to how horizontal drilling has tested and enhanced the geological model. Key reservoir parameters (e.g. connectivity, claystone distribution, grain size distribution, porosity, horizontal and vertical permeability) are discussed and their contribution to the success of the project evaluated.
The reservoir development of the Fife Field
Authors: CURRIER S. , GOWLAND S. , TAYLOR A. , WOODWARD M.
Published: April 2010

The Fife Field, located in the southern part of the Central North Sea. produced first oil in August 1995 after a fast-track appraisal and development programme. At that time it was predicted to contain 120 × 10
6
BBL STOIIP in a predominantly fine-grained sandstone of Volgian age of which an estimated 50 × 10
6
BBL was recoverable over a 4 year field life. Rapid water breakthrough and a fast water-cut rise in the first three production wells, all located crestally on the field, led to significant reappraisal and remodelling of the field. This paper describes the initial field development, gives an account of the work which followed the start-up of the field, and accounts for the early water breakthrough.
Reservoir management of the Wytch Farm Oil Field, Dorset, UK: providing options for growth into later field life
Authors: HOGG A. J. C. , EVANS I. J. , HARRISON P. F. , MELING T. , SMITH G. S. , THOMPSON S. D. , WATTS G. F. T.
Published: April 2010

The Wytch Farm Oil Field, currently on plateau, produces up to 110 × 10
3
BOPD, 17.6 × 10
6
SCF gas and 725 tonnes LPG per day. Original reserves are 450 × 10
6
BBL with a proven 230 × 10
6
BBL oil equivalent remaining. The Triassic fluvio-lacustrine Sherwood Sandstone, at 1535mTVDSS (true vertical depth, subsea), is the largest and most prolific reservoir. Approximately half the reserves are in an offshore extension being developed by extended reach drilling (ERD) at step-outs of up to 10.1 km from onshore Poole Harbour. Projects to increase reserves, extend plateau and slow decline include: additional ERD wells; infill drilling; miscible gas injection; and pattern water flooding of the low nett: gross Upper Sherwood all whilst maintaining reservoir pressure.

Reservoir description is central to realizing these opportunities for growth. Structural uncertainty has been reduced through acquisition of the first transition-zone 3D seismic survey in the UK. An extensive RFT (repeat formation test) and production log database has been acquired in the onshore and ERD wells. These dynamic data, together with static data from core and outcrop studies, and >21km of ERD formation evaluation logs, are used to develop a high-resolution, fluvio–lacustrine sequence architecture of the Sherwood. The deterministic model enhances predictability of flow barriers, baffles and high permeability intervals. This understanding of fluid flow and recovery provides the framework for economic evaluation, which, with clear communication of uncertainty across disciplines, is the key to successful management of the reservoir into later field life.
Characterization of fault zones in the Gullfaks Field for reservoir modelling
Authors: YIELDING G. , ØVERLAND J. A. , BYBERG G.
Published: April 2010

A fault-seal study has been performed for faults around the A platform of the Gullfaks Field, Northern North Sea. The operator’s depth grids and isochore maps were used to build a FAPS database. Together with petrophysical logs, these data were used to compute the distribution of shale gouge ratio (SGR: fault-zone % shale) over each fault surface.

Pressure data from exploration and production wells have been projected onto the modelled fault surfaces. Where well data permit, across-fault pressure drops at particular time instants during production are displayed. These dynamic pressure drops provide a guide to the permeability of the fault zones once flow has started.

The calculated fault parameters (throw and SGR) can be converted to other parameters such as fault-zone thickness and permeability. These can be used to derive fault transmissibility modifiers for reservoir simulations. The calculated properties are compatible with the recorded pressure history and tracer movement between wells.
An integrated approach to hydrocarbon emplacement in chalk, Norwegian North Sea Central Graben
Authors: ØXNEVAD I. E. I. , TAYLOR M. S. G.
Published: April 2010

North Sea Central Graben chalk reservoirs are unique in that they have exceptionally high porosities at several thousand metres depth. This is partly an effect of overpressure, but, equally important are the combination of diagenesis, fracturing, and the timing of hydrocarbon generation, migration and entrapment.

For chalk to serve as a reservoir, available porosity and permeability at the time of hydrocarbon migration are critical. Porosity in a normal chalk is reduced by early marine cementation, mechanical compaction and chemical compaction (i.e. dissolution and precipitation of calcite cement). To what extent these processes influence porosity evolution through time is related to the chalk’s burial history, specifically the pressure history, thermal history and the partial pressure of CO
2
(P

CO
2

).

This was demonstrated by modelling porosity evolution through time in a cross-section extending from crestal Valhall Field to basin areas. The modelling results show that at crestal Valhall the chalk is highly porous and only mechanically compacted. Thermal and pressure (P

CO
2

) conditions were unfavourable for carbonate burial diagenetic cement to form prior to ≈20 Ma. At this point, oil emplacement prevented further porosity reduction, despite increasing temperatures and favourable P

CO
2

conditions during continued burial. In basin areas, rapid burial and exposure to high temperatures combined with favourable P

CO
2

conditions, from ≈40 Ma until present, resulted in more extensive porosity reduction by mechanical and chemical compaction.

Permeability in chalk is significantly enhanced by fracturing. Chalk fractures if total stress (pore pressure + bending moment) is equal to or exceeds fracture pressure. Providing that fractures are open while hydrocarbons are migrating, these will serve as migration pathways. As for the modelled basin areas, absence of tensional fractures at the time of hydrocarbon migration prevented filling of potential reservoirs. Instead, hydrocarbons were directed laterally towards crestal Valhall where pore space and permeability enhancing fractures were available.

By combining the results from the chalk diagenesis and fracture studies with hydrocarbon generation, migration and entrapment modelling, the distribution of known chalk fields and dry holes in the area was reproduced. The approach taken in the study emphasizes the necessity of a detailed understanding of the processes behind empirical observations such as porosity values in North Sea chalk reservoirs, a full evaluation of all factors having an impact on fracturing, and the integration of this understanding with basin-scale hydrocarbon migration models. Despite still unresolved questions concerning the chalk hydrocarbon system, the achievements so far are promising and encouraging for future prediction of hydrocarbon accumulations.
Strathspey vertical-cable seismic survey: a North Sea first
Authors: LEACH P. E.
Published: April 2010

In 1995–96, the Strathspey Field Group (Texaco, Shell Esso, and Oryx) acquired and processed the first vertical-cable seismic survey in the North Sea. Strathspey is a tilled, eroded fault block, and production is from the Brent and Statfjord reservoirs. The eastern flank of Strathspey is marked by low-angle foolwall degradation complexes in both reservoirs. Historically, these features have been very difficult to image seismically, both on Strathspey and on neighbouring fields. Vertical-cable seismic, with its uniform distribution of azimuths and its economical 3D pre-stack depth migration, was judged to have the best potential to image these features. The survey was acquired in six swaths in the summers of 1995 and 1996. Processing of the pre-stack depth-migrated data volume was completed in October of 1996. The dataset shows remarkable improvement over the previous 3D dataset (vintage 1985). and compares favourably with the Brent Field dataset which was acquired immediately to the north of Strathspey in 1995. Improved data quality has allowed a more confident interpretation of the low-angle fault scarp features, as well as a more detailed structural model of both reservoirs, In addition, the superior data resulted in an improved assessment of the remaining exploration potential in the Strathspey area. The information gained from the interpretation of the vertical-cable seismic data has given the field partners more confidence in siting wells and in the reservoir simulation models.
Exploring the Shetland–Faeroes Basin using wide-angle seismic technology
Authors: BARTON P. J. , HUGHES S. , ZELT C. , MASOTTI R.
Published: April 2010

Densely sampled wide-angle seismic profiles using ocean-bottom seismometers have been used to obtain detailed velocity models of the Shetland–Faeroes Basin in both two and three-dimensions. We demonstrate that the wide-angle (refraction) technique, which employs dense spatial sampling to long offsets, may be successful in areas such as the Atlantic margin, where deep water and/or volcanic horizons mitigate against successful profiling using conventional methods. We employ a series of ray-trace and tomographic inversion procedures on travel time data from profiles across the basin axis to give detailed
in situ
velocity models and accompanying resolution and uncertainty estimates. Comparison of the
in situ
velocity of the Mid-Faeroe Ridge with deterministic lithology–velocity data from nearby boreholes strongly implies that Cretaceous–Tertiary shale and sandstone sequences extend to depths of 4.5 km. The presence of pre-Cretaceous sedimentary lithologies at 4.5–8.0 km depth is supported by
in situ
velocities of 4.0–4.5 km s
−1
which are best explained by well-consolidated sediments and are incompatible with likely constituents of the basement. The southeastern flank of the Mid-Faeroe Ridges is marked by a prominent fault marking a lateral velocity variation of about 0.5 kms
−1
. A rapid increase in velocity at 8 km depth suggests transition into the basement, whose velocity is similar to high-pressure measurements of basalts from the Faeroe Islands. Data from an areal grid of shots and receivers centred over the Mid-Faeroe Ridge have been inverted to give a fully three-dimensional velocity model of a small volume to depths of 10+ km. Variations in the depth of isovelocity surfaces from this model correspond closely with the geometry of the Ridge, and the position of the flanking normal fault and its adjacent basin to the southeast.
Three-component 3D borehole profile imaging program on Ekofisk Field
Authors: NIELSEN H. H. , DANGERFIELD J. , KEY S. C. , SØILAND G. V. , BERG L.
Published: April 2010

A complete series of 3D walkaway borehole profiles have been collected for the Ekofisk Field that are expected to image most of the crestal area of the field. This area has gas present in the overburden which obscures the seismic imaging using conventional surface seismic data. Good compressional images are obtained by undershooting the gas zones and taking advantage of the small Fresnel zones using the 3D walkaway technique. Considerable compressional to shear wave conversion was observed at the reservoir level in these profiles. Shear waves may be particularly suitable for imaging because they are less affected by gas than the compressional waves. Several 3D walkaway borehole profile surveys have been used to derive a 3D up-going shear image. This paper describes the results of this shear wave work from one of these surveys.
Seismic inversion as a vehicle for integration of geophysical, geological and petrophysical information for reservoir characterization: some North Sea examples
Authors: BUITING J. J. M. , BACON M.
Published: April 2010

Inversion of seismic trace data to acoustic impedance is an old technique which has become of greater value in the last few years as a consequence of improvements in seismic data quality. It can offer a useful pathway for inference of reservoir quality variation from seismic data, as is demonstrated by three examples from the Jurassic of the North Sea.
A, B AVO cross plotting and its application in Greenland and the Barents Sea
Authors: ISAACSON E. S. , NEFF D. B.
Published: April 2010

Recent amplitude versus offset (AVO) interpretations in the Norwegian Barents Sea and offshore West Greenland have identified subtle and complex anomalies which are best interpreted using a layer-specific, amplitude and gradient cross plot analysis scheme. The creation of AVO intercept (A) and gradient (B) seismic sections allows for a variety of stacks including A, B, A times B, and A plus B. Also, A versus B cross plots are easily generated to help define shale, wet sand and hydrocarbon trend lines that better differentiate the anomalies and provide information concerning the geological framework that created the AVO response.

Determination of the background trend on an A versus B cross plot is problematic in AVO analysis since variations in lithology and depth are interdependent, with both factors greatly influencing this trend. Also, the background trend is empirically defined by the AVO response of shale-on-shale boundaries or shale-on-silt reflectors, and this may not be indicative of the trend line for a shale-on-wet sand response. However, once the empirical background trend or wet trend is established, A and B data can be rescaled such that the shale line takes on a slope of −1. Potential hydrocarbon anomalies will then plot as data points with maximum scatter away from the normalized shale line. An A plus B section based upon a normalized shale line shows the potential hydrocarbon anomalies at maximum amplitude and the wet sands at minimum amplitude.

AVO analysis of A and B is generally performed together with forward modelling that generates theoretical responses for intercept amplitude (A) and gradient (B) parameters. The forward modelling helps validate the processing steps, give clues as to the non-uniqueness of various A and B responses, and integrates the geology into the study.

In the Fylla area, offshore West Greenland, an AVO analysis focused on large flat spots identified on the seismic data, as part of a licence application. A and B analysis was used to delineate trends in the data, to isolate three different classes of AVO anomalies which suggest the presence of hydrocarbons, and to provide insight as to the rock properties of the interbedded sandstones and shales.

An AVO analysis was also performed to help evaluate the prospectivity of an area in the Norwegian Hammerfest Basin. The purpose of the study was to establish the expected AVO response for the prospective interval from nearby gas discoveries and determine if similar anomalies exist within the prospect area. The AVO work consisted of forward modelling and A plus B analysis. Subtle AVO effects associated with gas in the Middle Jurassic section were identified.
Petroleum systems analysis of the Paleocene play in the West of Shetland area
Authors: JOWITT R. , HINDLE A. , JONES D. , ROSE P.
Published: April 2010

The Lower Tertiary petroleum system in the West of Shetland area has been reconstructed by integrating sequence stratigraphical interpretation, pressure data analysis and basin modelling with hydrocarbon migration pathways prediction.

Twelve sequences in the Paleocene–Early Eocene section can be grouped into three sequence sets. The lower two sequence sets are dominated by deep marine turbidite fan reservoir sandstones encased within hemipelagic shales. The youngest sequence set is dominated by a series of prograding delta facies rocks. A regionally extensive shale, deposited during a marine flooding event sits at the top of the oldest sequence set. This shale is an effective regional seal and pressure barrier. A study of well pressure data and sedimentary facies variations within the oldest sequence set has led to the identification of three pressure cells.

Structural modelling, heat flow mapping, vitrinite reflectance and apatite fission track analysis were used to reconstruct the thermal history West of Shetland. From this dataset, the Kimmeridge Clay Formation source-rock maturity and hydrocarbon generation history were modelled for several time periods. These results were used to generate migration pathways at the Base Tertiary unconformity which sits stratigraphically below the reservoirs in the oldest Paleocene to Eocene sequence set. The resulting model predicts an oil-prone southern province and gas-prone central province which accords with the Foinaven and Schiehallion oil fields in Quadrant 204 and the gas discoveries in Quadrants 206 and 214. The model also suggests the possibility of further oil potential in Quadrant 208.
Estimating undiscovered resources and reserve growth: contrasting approaches
Authors: CHARPENTIER R. R.
Published: April 2010

Assessments of oil and gas potential provide insight into future energy use. With regard to undiscovered resources, this paper contrasts the approach of pure statistical extrapolation with an alternate approach based on geological study of petroleum systems combined with a study of the exploration history of the assessed area. With regard to reserve growth, this paper contrasts a simplified approach with an approach relying on more detailed analysis of the data. An approach to estimating undiscovered resources using pure statistical extrapolation is quick, inexpensive and requires relatively little data and few personnel. Subjective judgment is not avoided, however, in that the choice of one assessment methodology over another is, in itself, very subjective. By calculating resource estimates based on a limited number of variables, statistical extrapolation ignores critical types of information. These methodologies commonly rely on assumptions that production history curves are simplistic, despite evidence to the contrary. Pure statistical extrapolation methodologies also inappropriately apply play-level exploration trends to larger features such as basins or countries. Reserve growth, the additions to booked reserves of previously discovered fields, is quantitatively a large portion of the potential additions to oil and gas supply. Reserve growth is not just a US phenomenon, but has been demonstrated in many countries. Even estimates that, by definition, should grow 50% of the time and shrink 50% of the time, grow much more often than they shrink. Nor was it brought about merely by OPEC countries trying to increase their production quotas.

Although M. King Hubbert’s work was advanced for his time, the reported success of his prediction of the year of peak US oil production has been overrated and is more than balanced by a lack of success in other predictions. The focus on the year of peak world oil production in Hubbert’s methodology distracts attention from the more important questions of what the real constraints on increased production are, and how regional distribution of resources has a great effect on economics and politics world-wide.
Exploration histories and future potential: overview
Authors: VINING B. A. , MUNNS J. W. , STOKER S. J. , ERRATT D.
Published: April 2010

The ‘exploration histories and future potential’ section of the
Proceedings
is designed to provide new insights for future exploration through leveraging learnings from past experiences. In this regard, the exploration histories of selected plays and fields from the Tertiary through the Palaeozoic of NW Europe are used to illustrate these learnings and to provide a guide to determining future potential. It is well recognized that, from a global perspective, NW Europe possesses world class petroleum systems. However, it is commonly perceived as a mature province for exploration and its future potential depends largely on our ability to understand better the known plays and our creativity to generate new plays. The North Sea region, in this context, benefits from the presence of two super source rocks, in the Kimmeridgian and Westphalian, and a diverse stratigraphy resulting in more than twenty plays from the Tertiary to the Palaeozoic. Historically, on a world-wide basis, the majority of stratigraphic traps have been discovered by serendipity. The wealth of high quality datasets in the North Sea and NW Europe, in combination with new advances in technology, provide an excellent natural laboratory to determine if untested plays and trapping concepts still remain.
The discovery patterns of the resources of the rift and gas provinces of the North Sea compared with some analogous provinces worldwide
Authors: SPENCER A. , CHEW K. , LECKIE G.
Published: April 2010

The discovered resources of the North Sea petroleum systems total around 100 billion barrels oil equivalent recoverable. Of these 70% occur in the Jurassic-sourced petroleum system of the Central and Northern North Sea (CNNS). The second major petroleum system occurs in the Southern North Sea (the Anglo-Dutch Basin, ADB), contains around 30% of the resources, is Carboniferous-sourced and gas-bearing. The discovery patterns of the resources in the two basins are here analysed by comparison with some analogous basins. The CNNS can be compared geologically with other oil-prone basins: Sirte, Bohai Wan, Gulf of Suez, Cambay/Bombay, Marib–Al Jawf and the southern part of the West Siberian basin. The ADB can be compared with gas-prone basins: Poland, Dnepr-Donets, Gippsland, Gulf of Thailand, NW Australia and northern West Siberia. The discovery patterns of the basins are compared with each other using:

resource growth with respect to exploration wells;

field size distributions;

discovered volumes with respect to exploration wells;

exploration efficiency.

A simple ‘ranking’ based on these criteria suggests that the CNNS is of middle rank while the ADB is, surprisingly, almost ‘worst in class’.
The remaining hydrocarbon potential of the UK Continental Shelf
Authors: MUNNS J. W. , GRAY J. C. , STOKER S. J. , ANDREWS I. J. , CAMERON T. D. J.
Published: April 2010

The United Kingdom Continental Shelf (UKCS) has been a very successful exploration province in the last 38 years, with an average technical success rate of 31% from its 2150 exploration wells. Although the peak of exploration activity on the UKCS occurred during the 1980s and 1990s, there have been 41 technical successes from 82 wells in the last four years, representing an improved recent success rate of 50%.

Estimates of undiscovered (yet-to-find) hydrocarbon volumes have been made from a database of prospects compiled over 20 years by the UK Government. This ‘bottom-up’ method provided an estimate of the yet-to-find resources at the end of 2002 of between 3.6 and 22.9 × 10
9
BOE recoverable. Methodology utilizing an inverse timescale to plot cumulative discovered volumes per year provides minimum estimates of between 4.5 and 9.5 × 10
9
BOE in place (
c
. 2.5 to 4.4 × 10
9
BOE recoverable). Pool size distribution methodology predicts that 11.5 × 10
9
BOE of in-place (
c
. 5.8 × 10
9
BOE recoverable) resources remain to be found on the entire UKCS. Geographically, the UK Central North Sea and Moray Firth area is predicted to contain the largest proportion of undiscovered resources (42%). Thirty-three per cent of the yet-to-find resources are judged to lie within the Atlantic Margin region.

Eighty-three per cent of existing UKCS fields and discoveries are located within structural traps. The majority of stratigraphic and combination traps occur in association with syn-rift (Upper Jurassic) and post-rift plays. Many of the major discoveries in these traps were found serendipitously, and there has been relatively little direct exploration for stratigraphic plays. In the UK North Sea, there are few substantial remaining structural traps, except at considerable depth with attendant reservoir quality, high-pressure and high-temperature risks. The future of exploration is believed to lie with the search for subtle stratigraphic traps. Deep-water sandstone stratigraphic plays within the syn- and post-rift sequences offer the greatest potential for substantial new resources.
Exploration history on the Norwegian Continental Shelf, 1990–2002: expectations and results
Authors: BLYSTAD P. , SØNDENÅ E.
Published: April 2010

The exploration activities on the Norwegian Continental Shelf during the period 1990–2002 were analysed; 300 wildcat wells were drilled and 134 discoveries made. A dataset consisting of 240 wildcat wells and 83 discoveries was studied. The volumetric in-place prognosis of the prospects were compared with the actual exploration results. The analysis indicates that exploration appears to have been determined by the chance of finding oil and that there is no obvious correlation between prospect volume, proximity to infrastructure and probability of discovery. Comparison of the prognosed and the discovered volumes shows that, in total, the prognosis is double the actual discovery volumes. This is mainly due to overestimation of oil prospects, as discovered gas tends to match the prognosis. The volume of discoveries smaller than 100 × 10
6
Sm
3
oil equivalents (OE) corresponds to the prognosis, whereas prospects larger than this are overestimated. The best match is found for prospects in the 50
–
100 × 10
6
Sm
3
OE size category. Exploration of prospects is undertaken with too great a risk and there is no relation between prospect size and probability of discovery, except for the very large prospects which have lower probability than the rest of the prospects. There is no evidence for better performance in mature areas and overestimation is characteristic for most companies. The match between prognosis and actual volume is good for fields (approved for development), whereas discoveries in the planning phase are significantly higher than prognosed. The disappointing discoveries are either still unclarified or unlikely to be recovered. Results of exploration activity constitute an important part of the QC of prospects reported to NPD when these data are used for the evaluation of the undiscovered resources. NPD uses modelled prospects for calculation of the undiscovered resources.