bluuebunny/crossref_metadata_2025 huggingface dataset:
Geological description of flow units in channel sandstones in a fluvial reservoir analogue (Loranca Basin, Spain)
Authors: Martinius A. W. , Nieuwenhuijs R. A.
Published: November 2010

Lithofacies heterogeneity in channel sandstones in a labyrinth-type reservoir outcrop are expressed by the nested correlation structure of experimental permeability semivariograms. First-rate correlation lengths are related to average set size or the average thickness of laterally accreted beds, second-rate correlation lengths to the average spacing of cosets or beds, and third-rate correlation lengths to the average spacing of surfaces truncating individual point bars within a meander loop. Three flow units are defined. Flow unit I comprises ribbon sandstone bodies and is characterized by large trough cross-stratified sets. Second-order bounding surfaces are dominant. Permeability is interdependent between two second-order bounding surfaces. Flow unit II comprises the lower part of meander loop sandstone bodies without grain size differences visibly expressed at the lateral accretion surfaces. Lithofacies and permeability characteristics are similar to flow unit I although the average set size and mean permeability are low. The average volume of flow unit II is largest. Flow unit III comprises the heterolithic upper part of meander loop sandstone bodies built up by ripple lamination in laterally accreted beds with distinct grain size changes. The latter form pronounced bounding surfaces and, significantly, determine two-dimensional permeability interdependency. The mean permeability is three times smaller than that of flow unit I. The spatial distribution of the flow units is mainly determined by climatic fluctuations from relatively humid to relatively arid conditions.
The Tiffany and Toni oil fields, Upper Jurassic submarine fan reservoirs, South Viking Graben, UK North Sea
Authors: Kerlogue Alison , Cherry Stephen , Davies Howard , Quine Mark , Spotti Giuseppe
Published: November 2010

The Tiffany and Toni fields lie at the western margin of the South Viking Graben in the Northern North Sea in UK Block 16/17. The reservoirs are composed of coarse clastic sediments of the Upper Jurassic Brae Formation, which were deposited by turbidity currents and debris flows in a submarine fan setting. The Brae Formation accumulated adjacent to the graben margin fault scarp and abuts pre-Jurassic rocks of the Fladen Ground Spur to the west. The Kimmeridge Clay Formation provides both the source of hydrocarbons and the seal for the reservoir.
Use of rock properties and AVO in the Everest Field development, UKCS
Authors: Barrett R. F. , Margesson R. W. , D'Angelo R. M.
Published: November 2010

The Palaeocene, Everest Complex, in the UK North Sea Central Graben, contains stratigraphically trapped gas condensate. Shear velocity logs were acquired in several wells. Rock property measurements on core from the Forties and overlying shale allowed anisotropy to be estimated. Comparisons were made between synthetic CMP gathers in a deviated well using measured logs, logs corrected for anisotropy and computed shear logs. AVO anomalies were seen at top and base of gas on both synthetic and real CMP gathers. These AVO responses can be enhanced by offset range stacking. Interpretation of seismic data, specially processed for AVO and calibrated through modelling, has allowed optimal siting of wells and has been a valuable tool in the field development.
Romania's petroleum systems and their remaining potential
Authors: Popescu Bogdan M.
Published: November 2010

Eighteen petroleum systems (PS) - particular combinations of source rock maturation and migration to reservoirs in a confined area of a sedimentary province - have been identified in Romania. Most hydrocarbons were expelled or re-migrated into the reservoirs after the Late Styrian orogenic phase , 12-14 Ma years ago. Hydrocarbons mostly accumulated in fields during the Late Sarmatian- Pliocene interval, after the Moldavian orogenic phase. Most gas in the Sarmatian-Pliocene reservoirs of the post-tectonic basins is biogenic. The thick Late Miocene-Pliocene sediments of the Carpathian foredeep and Transylvania Basin have not reached the stage of an effective thermogenic petroleum system. Evaluation of exploration history and fractal distribution laws of discovered hydrocarbons suggest future discoveries in the five major onshore PS analysed of 15 Mt of crude oil. These new discoveries will be in: foreland plays in little explored deep, central basin areas, structural, stratigraphic and combination traps of the subthrusted areas; structural traps of deeper duplexes of the Carpathian Palaeogene PS and in stratigraphic plays of biogenic PS.
Heavy mineral suites in the Statfjord and Nansen Formations of the Brent Field, North Sea; a new tool for reservoir subdivision and correlation
Authors: Morton Andrew C. , Berge Cato
Published: November 2010

Heavy mineral data provide an independent basis for subdivision and correlation of the Statfjord-Nansen reservoir sequence in the Brent Field, UK North Sea. Because of its continental fluvial depositional environment, this sequence lacks a well-defined biostratigraphically-based correlation framework. Detailed well correlations are difficult because of the heterolithic nature of the reservoir and the lack of chronostratigraphically significant markers. Three major heavy mineral zones and a number of subzones have been established. These can be confidently correlated in cored sections across the Brent Field. The correlations made using the heavy mineral scheme generally parallel the boundaries between reservoir units, giving confidence to the current reservoir zonation and indicating that it has a sound geological basis. However, the mineralogical zonation of a crestal, faulted well, 211/ 29-D44 (BD44), differs significantly from the reservoir zonation. This illustrates the difficulties inherent in establishing field-wide correlations without support of independent correlation schemes.
Hydrocarbon generation in relation to thrusting in the Sub Andean zone from 18 to 22 degrees S, Bolivia
Authors: Moretti I. , Baby P. , Mendez E. , Zubieta D.
Published: November 2010

Formation of the Bolivian eastern cordillera started at the end of the Oligocene and continues to the present day with thrusting affecting the Sub Andean Zone since late Miocene. The 'classical' source rock is the Devonian, but the Silurian interval has some potential. Their initial original potential is not high but they are thick (700 m, Los Monos Fm) and may be thicker still due to stacking in thrust duplexes. The three phases of sedimentation during the Tertiary each start with conglomeratic deposits and are discordant over the previous one. Seismic data allow us to correlate these steps with three periods of tectonic accretion: Late Miocene (Tariquia Fm), Pliocene (Guandacay Fm) and Plio-Quaternary (Emborozu Fm). Modelling demonstrates two phases of hydrocarbon generation. A first phase from Devonian to Carboniferous is due to the deepening of the Palaeozoic basin. The second phase of maturation is due to the Tertiary deposits in the foreland and under the piggyback basins. The central area (Santa Cruz) has never been more deeply buried than during the Palaeozoic and has been a high during the Tertiary.
A tectono-stratigraphic framework for Yemen and its implications for hydrocarbon potential
Authors: Ellis A. C. , Kerr H. M. , Cornwell C. P. , Williams D. O.
Published: November 2010

The Late Jurassic Marib Al Jawf Basin is part of a rift system extending southeastwards into the less well known Wadi Hajar Basin. This rift system may be one arm of a Late Jurassic failed triple rift which also included the Masilah Basin to the east, and the Sir Basin to the north. Late Jurassic rifting is shown to be diachronous, younging eastwards. Renewed rifting during the Early to Mid Cretaceous was accompanied by deposition of the newly recognized Furt Formation. This second rift phase initiated movement on the N-S striking 47 degrees E Fault, which probably extends southwards into Somalia. Extension in the Jeza-Howarime Rift System may also have commenced at this time. Oman Mountain orogenesis led to renewed subsidence in the east, and was followed by polyphase Tertiary rifting, inversion and localized gravity-driven extension on the continental margins. As a result of these events, a number of distinct petroleum systems developed.
The Zechstein Stassfurt carbonate hydrocarbon system of the Thuringian Basin, Germany
Authors: Karnin W. D. , Idiz E. , Merkel D. , Ruprecht E.
Published: November 2010

The Thuringian Basin is the oldest hydrocarbon province in Eastern Germany: wet gas and oil accumulations have been discovered since 1930. After a long inactive period of about twenty years, exploration for hydrocarbons now continues with improved methods. Carbonates and evaporites of the Permian Zechstein comprise the source, reservoir and seal for the main gas and oil play in the area. Today, they are buried less than 1000 m deep over the major part of the basin. Modelling of the burial history of the basin indicates that up to 1500 m of Mesozoic strata were eroded during a Late Cretaceous inversion event. Peak hydrocarbon generation occurred just prior to this inversion, implying that hydrocarbons have been effectively trapped in the reservoirs since that time. In addition, dry gas and nitrogen appear to have been sourced from pre-Zechstein intervals, which, with respect to nitrogen, poses a severe exploration risk.
Thorium distribution in some North Sea sandstones; implications for petrophysical evaluation
Authors: Hurst Andrew , Milodowski Anthony
Published: November 2010

Separation of minerals from reservoir sandstones into grain size classes, and chemical and mineralogical analysis, allows accurate description of relations between Th occurrence and mineralogy. Detrital heavy minerals, and particularly monazite, are found to account for the majority of the Th. Some heavy minerals occur as inclusions within detrital quartz which, because of its abundance, may account for a substantial proportion of the Th content in individual samples. Minor concentrations of Th are identified in diagenetic rare earth element (REE) phosphates. Kaolinite is not associated with Th-enrichment. Determination of Th content is not recommended as a guide to the kaolinite content of sandstones. Th content may be useful for identification of monazite and lithostratigraphic applications.
Gravity drainage during gas injection
Authors: Naylor P. , Sargent N. C. , Crosbie A. J. , Tilsed A. P. , Goodyear S. G.
Published: November 2010

The drainage of oil under gravitational forces has been an important mechanism in the production of many oil fields. In order to extend the economic implementation of gas injection into more marginal fields, a reduction in the uncertainties associated with gravity drainage is required. This paper describes a series of three tertiary, nitrogen experiments which investigated the effect of permeability on gravity drainage. The experiments were conducted at low pressure using long, vertical, water-wet sandstone cores and decane in the presence of connate brine. The residual oil saturation following 62 days of nitrogen injection in a 0.37 mu m
2
core was 0.26, following 53 days of nitrogen injection in a 1.5 /mu m
2
core was 0.10 and following 63 days of nitrogen injection in a 2.0 /mu m
2
core was 0.10. The variation of the oil and brine saturations were determined as a function of space and time for each experiment using a radioactive tracer technique. This independent measurement of both oil and brine in situ saturations is a new development and enables core artefacts to be identified and relative permeabilities to be derived. Detailed analysis of the 2 mu m
2
experiment showed that the oil relative permeability was independent of position and was only a function of oil saturation. The relative permeabilities are characterized by a zero asymptotic residual oil saturation and a Corey exponent of approximately four, which is higher than the value of three proposed from theoretical models of film drainage. A numerical simulation of this experiment gave a good match to the production and in situ saturation data. Determination of oil and brine relative permeabilities under a flow regime are presented which are representative of gravity drainage during gas injection. The method outlined gives added confidence when assessing field development options.
Early discordant diagenesis in the Brent Group, Murchison Field, UK North Sea, detected in high values of seismic-derived acoustic impedance
Authors: Ashcroft W. A. , Ridgway M. S.
Published: November 2010

Acoustic impedance inversion of seismic data in the Murchison Field, UK North Sea has revealed a zone of high acoustic impedance within the Rannoch Formation of the Brent Group which is discordant to stratigraphy. The high values of acoustic impedance are caused by the diagenetic growth of siderite and pyrite early in the burial history of the rocks, probably while semi-consolidated at a depth of less than 1000 ft. The zone is approximately parallel to the overlying Base Cretaceous unconformity and its formation may have been controlled by a temperature gradient and/or groundwater chemical boundary that was parallel to ground surface at that time.
The depressurization of water-flooded reservoirs; wettability and critical gas saturation
Authors: Hawes R. I. , Dawe R. A. , Evans R. N. , Grattoni C. A.
Published: November 2010

The influence of wettability on the formation, growth and mobilization of bubbles formed when solution gas is released from water-flood residual oil have been visually observed in a series of experiments. The experiments were performed using a mixture of low boiling point hydrocarbons, which had a positive spreading coefficient for the oil phase in contact with water and its own vapour. In an oil-wet matrix, nucleation of gas bubbles occurred on the surface of the matrix. While it was impossible to determine where nucleation occurred in the water-wet condition, the results suggest that wettability influences the gas nucleation behaviour. In a water-wet system, the oil-water interfacial tension controlled the growth pattern for the gas bubbles, but in an oil-wet system the gas-oil interfacial tension was the controlling parameter. As a result, it seems likely that wettability influences the critical saturation for mobilization of the gas phase. The behaviour of the oil phase during depressurization is influenced by wettability. In a water-wet system the physical form of the oil is changed from immobile droplets into films which may be transported with the gas phase, and in which the oil is mobile. In contrast in an oil-wet system, the oil phase can move as films when the gas is released from solution but generally will not initially move over many pores.
A foam pilot test aimed at reducing gas inflow in a production well at the Oseberg Field
Authors: Aarra M. G. , Skauge Arne , Sognesand S. , Stenhaug M.
Published: November 2010

In June 1994 a foam pilot test was performed in a production well at the Oseberg Field, North Sea. The Oseberg Field is developed by up-dip gas injection and is currently experiencing gas breakthrough in some of the production wells. The production well, B-27, chosen for the test is located in the Gamma structure and produces from the Oseberg Formation, a highly permeable (2-3Darcy) homogeneous sandstone. B-27 is perforated in 5 intervals in the lower section of the Oseberg Formation. To evaluate the gas-blocking effect of foam within a short time frame, and to increase the accuracy of measurements, only the top perforation interval of B-27 was treated and back-produced. Foam was generated by slug-injection of gas and surfactant dissolved in seawater. Gas-oil ratio (GOR) was reduced by about 50% after foam treatment, compared to pre-foam production tests. The foam pilot-test in production well B-27 was operationally successful. The test has shown that foam can be generated by slug injection of gas and surfactant solution and that foam can reduce GOR even in zones with high oil influx. The foam treatment was effective in reducing gas inflow over the six month period of the test.
Temperature and uplift history of Bjornoya (Bear Island), Barents Sea
Authors: Ritter Ulrich , Duddy Ian R. , Mork Atle , Johansen Harald , Arne Dennis C.
Published: November 2010

Apatite fission track age data from the majority of the 14 samples studied indicate cooling below c. 110 degrees C beginning 60 to 90 Ma ago. Vitrinite reflectance modelling suggests temperatures prior to cooling reached > 160 degrees C in the north and 150 to 160 degrees C elsewhere. Temperatures from fluid inclusions in quartz cement from the Carboniferous Nordkapp Formation may have reached 139 to 151 degrees C. Zircon fission track data from the basement indicate that the maximum temperature during Hecla Hoek metamorphism was less than 290 degrees C. Circumstantial evidence suggests that temperatures prior to deposition of the Permian Miseryfjellet Formation were probably much lower than those during the Mesozoic. Maximum eroded overburden above the Miseryfjellet Formation can be estimated at 2900 to 4200 m using various different methods. The resulting geothermal gradients suggest palaeoheat flow conditions close to those of today.
Seismic validation of reservoir simulation using a shared earth model
Authors: Gawith D. E. , Gutteridge P. A.
Published: November 2010

This paper concerns an example of cross-disciplinary integration: the use of seismic modelling based on a shared earth model to validate reservoir simulation. Whole-field simulator models and finer-scale sector models can be generated from the same detailed geological description in a shared earth model, ensuring that they are consistent. However, it is possible for some aspects of the simulation to depart from the geology, making predictions unreliable. For seismic validation, synthetic seismic volumes are produced from a shared earth model containing fluid data fed back from the simulator. Features in the synthetic which are caused by fluid movements, are then looked for on the real 3D seismic data. If the seismic data confirm the simulator's results in the spaces between history-matched wells, greater confidence can be had in its forward predictions. The methodology is illustrated using the Magnus oil field in the UK North Sea.
Caucasus wedge-thrust structures and oil-gas potential
Authors: Sokolov B. A.
Published: November 2010

Structural elements with an arched shape in plan occur in the Great and Lesser Caucasus foothills. Their formation is due to the presence of transverse buried rifts, which are overthrust by foreland folds having the form of a wedge in plan. The resulting structures are favourable for the presence of oil and gas accumulations. The Daghestan wedge-nappe (DWN), named by Shatskiy in 1925, is a tectonotype for such structures. The DWN has been thrust over a large rift trough with a transverse orientation to the strike of the Eastern Caucasus folds. Sedimentation and intensive heating through the Mesozoic and Cenozoic resulted in this trough becoming an area of hydrocarbon generation. Wedge-nappe structures are likely to occur widely in all fold belts, such as the Ural and Verhoyansk belts in Russia, the Bulgarian Eastern Balkans and the Suleyman Mountains in Pakistan.
Factors controlling the destruction or preservation of giant light oilfields
Authors: Macgregor Duncan S.
Published: November 2010

Study of a database of 350 giant oilfields show these to be dynamic short-lived phenomena, with a median age of 35 Ma. A third show evidence for post-entrapment destructive processes, particularly erosion, fault leakage, gas flushing and biodegradation. Many cases of biodegradation may occur prior to complete filling of the oilfield. Re-entrapment of oil released from spilling or breached traps is common. The main controls on oilfield preservation are post-entrapment tectonism and seal type, with temperature and hydrodynamic regimes being secondary factors. Destructive processes are concentrated in shallow and deep zones and in seepage-prone traps such as compressional anticlines. Such factors strongly influence the distribution of preserved light oilfields, with preservation potential maximized in tectonically quiescent basins with evaporite seals, e.g. the Middle East and the Permian Basin. More attention is required, particularly in older petroleum systems, to models involving post-entrapment leakage and re-migration.
Development of the slumped crestal area of the Brent reservoir, Brent Field; an integrated approach
Authors: Coutts S. D. , Larsson S. Y. , Rosman R.
Published: November 2010

The Brent Field consists of a major, westerly dipping fault block, with a crestal area broken up into a series of slumped fault blocks. The primary phase of development has concentrated on water flooding the West Flank, but effort is now being applied to recover the oil in the slumped blocks. This paper describes the various studies undertaken to formulate a development plan for the estimated 13 x 10
6
m
3
(80 MMSTB) of oil reserves in the slumps of the Brent Reservoir and presents initial well results. A valid geological interpretation was crucial to successful development planning for the slumps. Structural interpretation is difficult due to limited seismic resolution, but the geological model has been supported by a review of structural analogues and by the limited well performance data. The slump faults are interpreted as running predominantly north-south. As such, they provide a significant barrier to west-east flow, while allowing better communication in the north-south direction. Development options have been evaluated by reservoir simulation based on this geological interpretation. East-west communication will be too poor to enable the slumps to be developed at reasonable rates by relying solely on pressure support from West Flank water injection. In addition, the use of horizontal wells, as compared with conventional deviated wells, has been shown to give significant benefits by providing offtake points in several slump blocks with one well, thereby improving the sweep efficiency and increasing the recovery whilst optimizing rig usage. A development plan has been formulated on this basis with a series of roughly parallel east-west horizontal oil producers, interspersed with horizontal water injectors. This plan is now being implemented and the first wells are now on production.
Spontaneous imbibition in two different chalk facies
Authors: Milter J. , Oxnevad I. E. I.
Published: November 2010

An evaluation is made of the imbibition potential of two different chalk facies from outcrops in England and Denmark. Both chalk facies have low permeability, moderate to high porosity, and comparable low insoluble residues (< 5%), but different texture, depositional origin and diagenetic history. Spontaneous imbibition experiments were carried out on plugs with low initial water saturation and North Sea dead oil. Distinctly different production rates and production plateaus were observed for the two chalk facies. Careful investigations of the rock framework and pore system of the sample material form the basis for a theoretical description of wettability alteration and possible imbibition processes in the two chalks. The theoretical descriptions are used to rationalize the results from the spontaneous imbibition experiments. The results suggest that by knowing lithology, depositional history and degree of diagenetic alteration a relative potential of spontaneous imbibition in different chalk facies may be elucidated.
Hydrocarbon generation modelling in the west of the Moesian Platform, Romania
Authors: Pene Constantin
Published: November 2010

Silurian, Middle Carboniferous, Middle Jurassic and Sarmatian shales as well as Devonian bituminous limestones are thought to be main the source rocks in the study area. The thermal maturation level of the source rocks was computed using burial history curves for 175 wells. Maps of isoreflectance show that all the source rocks are mature in the north of the study area. The onset of oil generation from most of the source rocks took place during Sarmatian and Pliocene times, after most traps were formed. The calculations suggest that the volumes of hydrocarbons available to be reservoired are much greater than the volumes discovered to date.
Draugen Field development; the role of gravity drainage and horizontal wells
Authors: Reinholdtsen B.
Published: November 2010

The Draugen Field is an elongate, low relief, anticline containing mainly multi-Darcy sandstones. Oil initially in-place (STOOIP) is 182 x 10
6
Sm
3
. The 1987 Plan for Development and Operation (PDO) assumed a central cluster of 6 deviated production wells and 3 subsea water injectors at each end of the field. In addition two subsea wells would provide early production. Unsteady state relative permeability data indicate a residual oil saturation of 35%. In the full field simulation model this was increased to 40% to account for small-scale heterogeneity. The model yielded a recovery of some 67 x 10
6
Sm
3
. Modern steady state and centrifuge techniques have since demonstrated a long tail of very low oil relative permeability before reaching a residual oil saturation of some 15%. Fine grid simulations translated this into a gravity segregation process behind the displacement front. Other fine grid models reveal that horizontal wells will yield a slower build up of water cut than vertical wells. The increased productivity of the horizontal wells reduced the required number of platform producers from 6 to 5. Pseudo-relative permeabilities were developed to represent fine grid model performance in a new sophisticated full field model. This model predicted an ultimate recovery of 94 x 10
6
Sm
3
(40% increase). The additional predicted recovery is attributed to a reduction of the effective residual saturation and delayed water production associated with horizontal wells. In October 1993 Draugen started production from one horizontal subsea well, which has since demonstrated a better than expected coning performance. Production from platform wells was initiated in June 1994 with initial well rates up to 8000 Sm
3
per day, confirming the expected high productivity of horizontal wells. Optimization and tuning of facilities has since allowed the peak production rate for the field to be increased from the planned 17 500 Sm
3
per day to a present actual level of 24 600 Sm
3
per day. Further de-bottlenecking is ongoing with the aim of increasing process capacity.
Alluvial architecture and differential subsidence in the Statfjord Formation, North Sea; prediction of reservoir potential
Authors: Ryseth Alf , Ramm Mogens
Published: November 2010

Statfjord Formation sandstones (Rhaetian-Sinemurian) form important reservoirs in the North Viking Graben, and are still a target for exploration drilling. Sedimentological analyses from the Tampen Spur and Horda Platform show that the reservoir potential is controlled by the distribution, density and stacking pattern of multistorey/multilateral fluvial channel sandstones within successions of interbedded fluvial and interfluvial deposits. Formation thicknesses vary from about 50 m to more than 500 m within the study area. Empirical relationships linking the sandstone content to succession thickness, show that the proportion of channel deposits varies systematically with thickness, and indicate that the most sandstone-prone reservoirs associate with low to moderately high formation thickness. This suggests that differential subsidence influenced the architecture of the Statfjord Formation. Sandstone body stacking patterns derived from correlation panels show a sequential ordering of multilateral/multistorey sandstone sheets and intervals with a higher portion of mudrock and more isolated sandstone bodies. Sequence stratigraphic boundaries are recognized at the bases of multilateral sandstone sheets, and stacking patterns form a basis for detailed correlations within structural compartments with constant formation thickness. However, the number of recognizable sequences increases with increasing succession thickness, and the correct correlation of sequences across major fault systems pose major problems to stratigraphic studies.
Use of palynofacies characterization in sand-dominated sequences, Brent Group, Ninian Field, UK North Sea
Authors: Sawyer Mark J. , Keegan James B.
Published: November 2010

Palynofacies characterization employing an innovative technique was successfully conducted on the sand-dominated lower Brent interval of the Ninian Field, which had previously been described as 'palynologically barren', and was used to aid in geosteering the field's first horizontal well. Pre-planning for the well included analysis on the cored interval of a neighbouring well where fifteen potential palynofacies/palynological events were recognized. All were distinct and consistent with the zonal breakdown and sedimentological description for the interval studied. The technique has been subsequently used at the well-site, in conjunction with Anadrill's GST (Geosteering Tool), to successfully maintain the well within its target window and close to its intended well path. More recently the technique has been used to successfully re-appraise and improve the stratigraphic understanding of wells within the field's structurally complex degradation sheet.
Cenozoic compressional structures on the NE Atlantic margin; nature, origin and potential significance for hydrocarbon exploration
Authors: Dore A. G. , Lundin E. R.
Published: November 2010

Compressional structures of Cenozoic age are ubiquitous features of the NE Atlantic margin between the western Barents Sea and offshore western Ireland. The structural suite includes simple domes or anticlines, reverse faults and broad-scale inversions. Our analysis focuses on a recently delineated group of structures in the Norwegian Sea, although these are placed in the context of similar features on the Barents margin, West of Shetlands, on the Faroes and their surrounding shelf, and in the Rockall Trough. Some (although not all) of the compressional anticlines were formed at the sites of pre-existing Cretaceous-Palaeocene depocentres. They show a multi-phase growth history. In the Norwegian Sea, particularly important phases occurred in the middle Eocene to early Oligocene and in the Miocene. We interpret the formation of these structures as a natural outcome of the transition to sea-floor spreading that occurred in the early Eocene. From this time, extremely thick sedimentary successions that had accumulated during some 300 million years of extensional tectonics were subjected to mild compression. The overall compressive stress field can be explained in terms of spreading in the adjacent ocean (ridge push) and by the distant effects of Alpine tectonics. In a plate-wide sense these effects can be regarded as two sides of the same coin. The origin of the Norwegian Sea structures is most easily visualized in terms of ridge push. NW-SE transfer zones, characteristic of the entire margin, are strongly implicated in these tectonics. A kinematic model is described that links significant structuring with a change in the spreading direction of Oligocene-Miocene age (35-20 Ma, A13-6). The compressional structures are mainly observed by their effect on sediments and volcanics of Cretaceous and Cenozoic age. They are frequently expressed in the present-day sea-floor relief, and in the case of the Faroe islands are probably responsible for present subaerial exposure. From the point of view of hydrocarbon exploration, the Cenozoic compressive anticlines have obvious potential as fourway dip closures or as components of structural-stratigraphic traps. The NW-SE fractures, orientated parallel or sub-parallel to the maximum horizontal stress direction, were probably periodically open for fluid flow from the time of NE Atlantic opening and onwards. They may therefore have facilitated migration from deeper source rocks or remigration from pre-existing hydrocarbon accumulations.
The external thrust system in southern Italy; a target for petroleum exploration
Authors: Lentini Fabio , Catalano Stefano , Carbone Serafina
Published: November 2010

In southern Italy the Apenninic-Maghrebian Orogen developed during the Neogene Africa-Europe collision as a regional-scale duplex structure. It shows an allochthonous hangingwall, widely overlying a mostly carbonate footwall, consisting of the External Thrust System. This formed since the Tortonian by the detachment of the sedimentary covers of the continental margins of the Africa and Adria plates. In the Southern Apennines the duplex geometry has favoured oil-trapping and fields have been detected in ramp-anticlines of the buried edifice. Similar geometries have been inferred in eastern and central Sicily. The re-interpretation of regional profiles in Sicily based on new field data defines deep-seated geometries showing several potential oil traps and the External Thrust System could represent a new target for petroleum exploration in the region.
Scale-up of near-miscible gas injection processes; integration of laboratory measurements and compositional simulation
Authors: Pande K. K. , Sheffield J. M. , Emanuel A. S. , Ulrich R. L. , DeZabala E. F.
Published: November 2010

Results from laboratory PVT measurements, special core analysis studies, and reservoir condition core-flood studies were used to develop and test the accuracy of a compositional simulation model in predicting near-multicontact miscible gas flood performance at the laboratory scale. Excellent agreement was obtained between the core-flood measured recoveries and GOR and the compositional simulation model predictions. No history matching was required to obtain this result. The choice of PVT and special core tests were critical to our ability to model the near-multicontact miscible displacement process without history matching. This result provides a high degree of confidence in using the compositional simulation model in cross-section and 3D element models to predict field-scale performance. Cross-sectional simulation sensitivities were performed in a geostatistical model of a dipping reservoir. Gas-flood recovery was on par with water-flood recovery for this cross-section.
Analysis of the pre-Tertiary rifting history of the Rockall Trough
Authors: Musgrove F. W. , Mitchener B.
Published: November 2010

The Rockall Trough is a large, lightly explored, deep water basin offshore West of Britain. Only the 132/15-1 well has penetrated Mesozoic section within the Rockall Trough encountering a syn-rift section, interpreted on seismic reflection data, of early Cretaceous age (Hauterivian-Cenomanian) lying directly on crystalline basement. Older rift events have been proposed in the Rockall Trough to explain the extensive crustal thinning (Beta = 3 to 5) and because of the presence of older rifts on adjacent basins. Although the evidence is not conclusive, analysis of seismic reflection data within the Rockall Trough and of rift system trends on an early Cretaceous plate reconstruction do not require or suggest older than Cretaceous rifts in the Rockall Trough but also do not preclude them. Structurally, the Cretaceous rifting is highly assymetric being dominated by faults downthrowing to the southeast. A model of a reactivated Caledonian foreland thrust belt is proposed similar to that reported on the adjacent Hebridean shelf.
Reservoir monitoring of the Magnus Field through 4D time-lapse seismic analysis
Authors: Watts G. F. T. , Jizba D. , Gawith D. E. , Gutteridge P.
Published: November 2010

During 10 years of production, crestal fluid pressures in the Magnus Field (UKCS) have dropped from 6650 psi to under 3500 psi leading to a two- to three-fold increase in the effective stress on the rock fabric. Petroacoustic measurements on cores indicate that this leads to a 12% increase in the acoustic impedance which, in theory, should be detectable using time-lapse seismic data. We analyse the difference between two 3D surveys shot over Magnus and relate this to dynamic changes in fluid pressure and saturation through time. The results demonstrate that, under certain conditions, fluid pressure changes may be detected in the reservoir and that fluid transmissibilities across faults can be deduced. Further, 4D seismic data may detect other dynamic processes, including thermal effects and cold water fracturing around injectors, and stress relaxation and fluid compositional changes around producers.
A method of estimating horizontal principal stress magnitudes from stress-induced wellbore breakout and leak-off tests and its application to petroleum engineering
Authors: Zhou S.
Published: November 2010

Existing methods and a newly proposed method are used to estimate the magnitudes of the horizontal principal stresses from stress-induced borehole breakouts and leak-off tests. Under the condition that the depth interval between leak-off and breakout is sufficiently small, so that the stress ratios sigma
H
/sigma
v
and sigma
h
/sigma
v
can be reasonably regarded as constants within the depth range, both horizontal principal stresses sigma
H
and sigma
h
can be resolved with some knowledge of breakout width. A comparison of the methods has been conducted with well data from the North West Shelf of Australia. The estimated stress magnitudes are generally consistent with the measured trend from neighbouring modified leak-off (or hydraulic fracturing) tests, and also indicate that the tectonic stress regime in the depth range from 2.6 to 2.9 km, at the location of the borehole, is likely to be on the boundary between extension and strike-slip. Knowledge of the in situ stress field provides a crucial development factor in petroleum engineering, such as the optimum design of inclined or horizontal drilling for maximizing wellbore mechanical stability and recovery from fractured reservoirs.
Oil and gas in reef reservoirs in the former USSR
Authors: Kuznetsov V. G.
Published: November 2010

Productive reefs in the former USSR are known from the Lower Cambrian to the Upper Jurassic. They contain more than 31% of the oil and about 29% of the gas resources of the FSU occurring in carbonate reservoirs. Giant and supergiant fields such as Karachaganak, Tengiz, Zhanazhol, Shurtan etc. are associated with reefs. Reservoir architecture and variation of reservoir properties depends upon the shape and origin of the reefs. Zones of improved reservoir properties are located in the central parts of dome-like reefs or in circumferential or ring-shaped zones in the atoll-like reefs. In asymmetric reef systems the best reservoir intervals are shifted towards the bioherm zone and forereef slope.
Illite dates record deep fluid movements in petroleum basins
Authors: Darby D. , Wilkinson M. , Fallick A. E. , Haszeldine R. S.
Published: November 2010

K-Ar age dates of authigenic illite from sandstones in the UK south Central Graben have a bimodal distribution. In contrast to established hypotheses of thermal triggers, this illite growth is explained by changes in hydrogeological history. Fluid motion during burial can hence be dated. Illite growth at 84-58 Ma on the graben margins was coincident with rapid subsidence of the Graben axis and consequent expulsion of pore fluids onto the margins. This event pre-dated both overpressure, and the secondary migration and accumulation of hydrocarbon in the region. Illite growth was probably caused by increased solute transport rates during pore fluid motion. Illite growth on an axial high (33-30 Ma) occurred during overpressured conditions. This was triggered either by: (1) downward fluid migration as a consequence of overpressure release. These fluids carried carboxylic acids or hydrocarbons from the highly overpressured Kimmeridge Clay Formation into the less pressured Fulmar Sandstone Formation; or (2) a decrease in water-rock ratios as fluid flow declined within the sandstones, as a consequence of overpressure build-up. Published experiments show that illite growth is favoured by low water-rock ratios.
The Predobrogean Depression in Romania and Moldova and its hydrocarbon prospects
Authors: Moroz Vasile , Neaga Vasile , Polonic Pamfil , Rosca Vlad
Published: November 2010

The Predobrogean Depression contains a Precambrian to Triassic sequence many kilometres thick, overlain unconformably by Middle and Jurassic strata 2 km thick, which are capped by a thin Cretaceous-Neogene cover. The depression lies southwest of the East European Platform and northeast of the Hercynian-Kimmerian North Dobrogea orogen. No significant hydrocarbon finds have been made. Scattered wells show bituminous clays at Vendian and Devonian levels and bitumen or hydrocarbon shows occur in Devonian dolomites, Permian Greywackes, Triassic sandstones and Jurassic strata. Minor oil and gas finds have been made in Neogene reservoirs but the main prospectivity is assessed to be in the Palaeozoic formations. Seismic data quality must be improved to reveal the structure of the Palaeozoic section.
Prospective Palaeozoic reefs in the southern part of the Barents Sea shelf
Authors: Ivanova N. M.
Published: November 2010

Palaeozoic carbonate build-ups have been identified from seismic data in the south of the Barents Sea Shelf at several stratigraphic levels: Upper Permian mainly in the west of the Barents Shelf, Lower Permian (Asselian-Artinskian), Carboniferous, Upper Frasnian-Famennian, Lower Frasnian, Lower Devonian, Silurian and probably Ordovician. Most of build-ups are identified in the southern part of the offshore the Pechora Platform (the Varandey-Adzvinskaya Structural Zone, Pechora-Kolvinskiy Aulacogen, Seduyakhinskiy Ridge). Large Late Devonian reefs, apparently of barrier type, are seen in the east of the Korginskiy High. Small carbonate build-ups are seen in the Carboniferous-Permian section in the Kola-Kanin Monocline and the West Kola Saddle, where a wide zone of reefs formed which appear to extend to the west to the Finnmark Platform. The wide extension of Palaeozoic reefs in the south of the Barents Sea Shelf, including the Pechora Shelf, increases the petroleum potential in the region.
The application of network modelling techniques to multiphase flow in porous media
Authors: McDougall S. R. , Sorbie K. S.
Published: November 2010

A review of the utility of network models is presented to describe multiphase flow at the pore-scale. Precise details of each set of simulations can be found in the appropriate reference and only the most pertinent results are presented here. The main aim of this paper is to highlight the effectiveness of network models as interpolative and interpretative numerical tools. Both primary and secondary capillary-dominated, two-phase displacements are considered and well-documented hysteresis effects are successfully reproduced. Waterfloods of mixed-wet media are subsequently described and associated variations in relative permeability and recovery efficiency reported. Optimum recovery is obtained from networks containing a 50-50 mix of oil-wet and water-wet pores. Finally, a discussion of unsteady-state drainage and imbibition models follows and these are applied to waterfloods in finely-laminated porous media. Results highlight the complex interactions between capillary forces, viscous forces and geological structure.
Application of surface prospecting methods in the Dutch North Sea
Authors: Baum Martin G. , Bleschert Karl-Heinz , Wagner Manfred , Schmitt Manfred
Published: November 2010

The characterization of invisible hydrocarbon micro-seepage intensities in surface sediments is used to evaluate subsurface hydrocarbon potential. A cost-effective multidisciplinary surface prospecting method, termed "BIG", is employed as a supplementary instrument to conventional exploration tools to assess the remaining prospectivity of a licence tract in the Dutch North Sea. Microbial investigations, molecular and isotopic gas characterization as well as UV fluorescence measurements are utilized for direct hydrocarbon detection in surface sediments. The definition and distribution of anomalous intensities is used as an index for the hydrocarbon potential in the deeper sub-surface. In combination with seismic information the BIG method can help to reduce exploration risk. It proves to be an effective instrument to determine the lateral extent of liquid hydrocarbon migration and to localize areas of prospective potential. This case history covers a successful application of the BIG method to investigate undetected hydrocarbon potential in an established producing province.
The influence of developments in information technology on the Exploration and Production Phase Model
Authors: Gabrielsen Roy H. , Moller-Holst Johan
Published: November 2010

In the light of demands for enhanced performance in the oil industry, the Exploration and Production Phase Model (EPPM), which includes the activities of exploration, development and production, and the IT systems that support them, is scrutinized. It is concluded that despite its weaknesses, exploration and production activities in the foreseeable future will be performed within the framework of the EPPM, but development of procedures and support systems will be accelerated. This process will be influenced by, and influence, IT development in the oil industry. It is suggested that the support systems for the EPPM will undergo a process of integration. Simultaneously, the system itself, or modules thereof, will acquire the characteristics of knowledge-based systems, aimed at decision support. Disciplines such as fuzzy logic, image processing, pattern recognition and visualization will also influence its development to various degrees. The growing complexity of the system and the continuous need to update, change and add modules will call for an object oriented approach in the design of modules.
Anatomy of growth fault zones in poorly lithified sandstones and shales; implications for reservoir studies and seismic interpretation; Part 1, Outcrop study
Authors: Burhannudinnur M. , Morley C. K.
Published: November 2010

Some normal faults developed in poorly lithified sediments in Miocene-Pliocene deposits of NW Borneo in the vicinity of Brunei display regular zonations of deformation bands. For fault displacements of a few metres the zones of deformation bands extend up to about 10 m into both the hanging wall and footwall. They range from closely spaced anastomosing seams within or adjacent to the main slip planes, to more widely spaced sub-parallel and parallel seams passing away from the fault zone. They reduce porosity and permeability, and if the faults are closely spaced, are likely to impact reservoir production characteristics and reserve estimates. In cross-section and map view fault zones are commonly composed of several important gouge and cataclasis zones, which branch and join, display listric detachments and various types of hard and soft linkage. Some of these geometries have been described as common characteristics of faults, others are comparatively rare. They have significant implications for the interpretation of seismic data.
Abnormal formation pressures in the West Siberian Mega-basin, Russia
Authors: Matusevich V. M. , Myasnikova G. P. , Maximov E. M. , Volkov A. M. , Chistiakova N. F. , Kanalin V. G. , Pupilli M.
Published: November 2010

The West Siberia Low Lands, a single gigantic basin-like depression filled by Mesozoic and Cenozoic sediments, is one of the most prolific petroleum provinces of the world. It is divided into two regions: Northern and Central-Southern. In the former the Mesozoic and Cenozoic sedimentary sequence ranges between 7 and 10 km thickness, whilst in the latter it is between 3 and 5 km. The present hydrogeological pressure regimes to be found in West Siberia (i.e. normal hydrostatic, abnormally high, abnormally low) could possibly reflect the different geodynamic evolution of basement mega-blocks. However, following a review of some Jurassic and Cretaceous reservoirs with abnormally high and low pressures, it is possible to observe that volume expansion of fluids stored in confined closed reservoirs seems the most likely cause of the abnormally high formation pressure. Abnormally low formation pressures are considered in some cases to be due to the cooling effect of permafrost, in others to the closeness of the reservoir to fractured and weathered basement.