bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
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.
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.
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.
The life cycle of the Netherlands’ natural gas exploration: 40 years after Groningen, where are we now?
Authors: BREUNESE J. , MIJNLIEFF H. , LUTGERT J. 
Published: April 2010

The discovery of the giant Permian Groningen Field in 1959 triggered the main phase of gas exploration in NW Europe. This paper deals with the history and future of natural gas exploration in the Netherlands. The aim is to explain the historical exploration process and use the results to predict the remaining part of the exploration life cycle. Data from over 40 years of continuous exploration and production are presented and analysed for relationships between exploration and production (E&P) activity levels (licence area coverage, seismic surveying and drilling rates) and reserves growth. The E&P data are further investigated in terms of the exploration efficiency. After more than 1000 exploration wells drilled, the cumulative reserves growth curve still shows little sign of creaming off. At first sight, this observation would appear to indicate a not very efficient historical exploration process. The paper will try to explain the impact of the underlying dynamic factors such as added information through time, technology development and infrastructure extensions.
Past exploration has revealed part of the total natural distribution of gas accumulations present in the Netherlands subsurface. The best known, i.e. least uncertain, part of the distribution consists of discovered accumulations (although changes in the assessment of this part of the portfolio still occur). Next comes the presently known portfolio of mapped prospects, identified and assessed according to proven play concepts. There is already some of uncertainty as to their actual subsurface volumes. Finally, from the observation that new prospects have been identified even in recent years, it is proposed that the perceived prospect portfolio will also behave dynamically in the future. Indicators of the maturity level and the estimated ultimate potential of the main play areas are derived. Today’s remaining potential is the source of future exploration. However, the actual outcome of future exploration is not determined by geology alone: business activity levels and exploration efficiency will be shown to be at least as important in the prediction of discovery and production rates.
The Buzzard Field
Authors: DORÉ G. , ROBBINS J. 
Published: April 2010

The Buzzard Field is one of the largest fields to be discovered on the United Kingdom Continental Shelf in the last 25 years; it has a current reserves estimate of over 400 × 10
6
BBL. It lies some 50 km northeast of the Scottish mainland and 20 km west of the Ettrick Field in a water depth of 300 ft.

The Buzzard Field was discovered in May 2001 by well 20/6-3. This well encountered high quality 32° API oil trapped within a latest Oxfordian to Early Volgian age reservoir informally defined here as the Buzzard Sandstone Member. The side-track penetrated an oil–water contact at 9194 ft TVDSS, establishing a minimum hydrocarbon column of 750ft. The field was the subject of an appraisal programme in late 2001 and early 2002, with eight wells and side-tracks drilled to define the field extent. These wells, coupled with a continual improvement in the quality of the seismic data, have helped to reduce the uncertainty associated with estimates of the STOIIP and reservoir geometry.
The trapping mechanism for the field involves a complex stratigraphic pinchout of reservoir sands within shales of the Kimmeridge Clay Formation. This is combined with a downthrown faulted closure against Palaeozoic rocks. The Buzzard Sandstone Member comprises base of slope, submarine gravity flow sands with excellent porosity and permeability characteristics.
The Caister–Murdoch System (CMS) III Carboniferous cluster development, UK Southern North Sea
Authors: COOPER M. M. , EASTON S. D. W. , LYNCH J. J. , FOZDAR I. M. 
Published: April 2010

The Caister–Murdoch System (CMS) III development comprises five separate Late Carboniferous Westphalian gas accumulations that surround the CMS transport hub in Quadrant 44 of the UK Southern North Sea: Hawksley, Murdoch K, McAdam, Watt and Boulton H. All are relatively small, single-well discoveries and most have been lying undeveloped for several years.
The following factors have contributed to their development: new techniques for seismic mapping and visualization have allowed a more complete understanding of the field geometries and trapping styles and greatly facilitated well design and reduced planning costs; a better understanding of Carboniferous reservoirs, including a more detailed sub-division of the Westphalian B and C/D that has led to more optimal targeting of the development wells; a unitized agreement between the parties who have equity in the satellites and transportation systems negotiated prior to project sanction; and the consecutive development of five fields reducing the overall cost and risk of the project.