bluuebunny/crossref_metadata_2025 huggingface dataset:
The Captain Field, UK North Sea; appraisal and development of a viscous oil accumulation
Authors: Pinnock S. J. , Clitheroe A. R. J.
Published: November 2010

The Captain Field is located in Block 13/22a in the Western Moray Firth Basin of the UK North Sea, 80 miles northeast of Aberdeen in a water depth of 340 ft. Hydrocarbons are trapped in two geographical regions, the Main and Eastern closures, both with a significant stratigraphic pinchout component. The principal reservoirs are the Lower Cretaceous Upper and Lower Captain Sands, which are predominantly of turbiditic origin. Reservoir quality is uniformly excellent with in situ permeability averaging 7 D and porosity in the range 28-34%. The reservoir is largely unconsolidated sandstone with the depth to the crest of the field at "2700 ft TVDSS. The reservoirs contain a total oil-in-place of 1500 MMBO. The Upper Captain Sand has a small associated gas cap containing 29 BCF gas-in-place. The oil is heavy, by North Sea standards, with oil gravity ranging from 19 degrees and 21 degrees API and in situ viscosity between 88 and 47 cP, at the mean reservoir temperature of 87 degrees F. The fluid properties and offshore location necessitate the employment of innovative horizontal drilling methods, completion design and artificial lift technology in order to achieve an economically viable field development. Extended reach horizontal wells, with reservoir completion lengths of up to 6500 ft, are proposed for all oil producers and water injectors. Development risks were significantly reduced following two appraisal drilling campaigns in 1990 and 1993 culminating with the successful drilling and extended testing of a prototype horizontal field development well (13/22a-10). First oil production commenced from the Captain platform in early 1997.
The diversity of hydrocarbon habitat in Russia
Authors: Tull Simon J.
Published: November 2010

The setting of the petroleum basins of Russia varies from Precambrian cratons to Tertiary active margins. Four economically and strategically important basins illustrate this diversity. The North Sakhalin Basin is a Tertiary strike-slip basin supplied with Oligocene-Pliocene reservoir sands, and seal- and source-forming mudrocks by the palaeo-Amur delta. Miocene diatomites are additional source rocks. Plio-Pleistocene structuring was crucial to hydrocarbon entrapment. The West Siberia Basin contains identified oil reserves of 60 billion bbl and 1400 tcf gas, respectively 47% of the oil reserves of the CIS and 77% of its gas reserves. The world-class Upper Jurassic Bazhenov source rock and a high impedance entrapment style are the keys to the productivity of the basin. The Timan-Pechora Basin contains Ordovician-Triassic reservoirs and a major Late Devonian source rock. Hydrocarbon preservation is good despite the basin's complex history of subsidence and inversion. On the Siberian Platform in East Siberia 12 billion BOE reserves are sourced, reservoired and sealed by Upper Precambrian-Cambrian rocks. Protracted preservation times there reflect a stable geological setting.
Mesozoic-Cenozoic history of deformation and petroleum systems in sedimentary basins of Central Asia; implications of collisions on the Eurasian margin
Authors: Otto Simon C.
Published: November 2010

Internal deformation within the Eurasian continent during the Mesozoic and Cenozoic occurred in response to a series of discrete collisional events along its southern margin. Collisions are recorded from Late Triassic, Middle Jurassic, latest Jurassic, mid-Cretaceous and Late Palaeogene-Recent times. Periods of deformation recorded from sedimentary basins both close to and more distant from the southern margin of Eurasia can be related to these collisional events. The strain of each collision was accommodated both by intense deformation along the margin of Eurasia and by relative movement of continental blocks within the accretional collage of Eurasia along pre-existing heterogeneities. Additional mid-Jurassic and latest Cretaceous uplift events are not directly related to collisional events on the southern margin of the continent. Petroleum systems in both strike-slip dominated basins (such as the South Caspian and Turgay basins) and thrust-dominated basins (such as the Fergana and Afghan-Tajik basins) show the influence of deformation on trap formation and breaching as well as on the remigration and potential loss of hydrocarbons. Periods of deformation also have a direct influence on the timing of hydrocarbon generation.
Main oil source formations of the West Siberian Basin
Authors: Kontorovich A. E. , Moskvin V. I. , Bostrikov O. I. , Danilova V. P. , Fomin A. N. , Fomichev A. S. , Kostyreva E. A. , Melenevsky V. N.
Published: November 2010

Two strongly oil-prone source intervals are present in the West Siberian Basin, the Togur Formation (Early Toarcian, Early Jurassic) and the Bazhenov Formation (Volgian-Berriasian, Late Jurassic to Early Cretaceous). Clay sediments of the Togur Formation were deposited in a system of intracontinental sub-basins in the southern half of the West Siberian Basin. The marine deposits of the Bazhenov Formation accumulated throughout the entire basin. Two types of extractable bitumens and oils - marine and non-marine - may be identified from their isotopic carbon composition, sulphur content, bulk composition, and biomarker hydrocarbons (normal alkanes, pristane/phytane, C (sub 27-30) steranes, hopanes and homohopanes). Marine oils, accounting for 80% of oil resources, are sourced from the Bazhenov Formation. The genetic relationship between oils in Upper Jurassic and Cretaceous reservoirs and the organic matter from the Bazhenov Formation is indicated by great similarities in their biomarker hydrocarbon compositions and their maturation levels. Non-marine (lacustrine) oils are sourced from the Togur Formation and account for 11% of oil resources.
Intense basic magmatism in the Tunguska petroleum basin, eastern Siberia, Russia
Authors: Kontorovich A. E. , Khomenko A. V. , Burshtein L. M. , Likhanov I. I. , Pavlov A. L. , Staroseltsev V. S. , Ten A. A.
Published: November 2010

The Tunguska basin, eastern Siberia, contains 3.5-8 km of Late Precambrian to Triassic sedimentary and igneous rocks. Source-reservoir-seal systems are present throughout the Upper Precambrian to Permo-Carboniferous interval. Hydrocarbon generation and accumulation largely preceded the formation of the Siberian traps, a Late Permian to Middle Triassic association of effusive and explosive extrusives and intrusive dolerites. The intrusives occur mainly in Palaeozoic strata and have profoundly affected hydrocarbon accumulation. The major process is of destruction of hydrocarbon accumulations, owing to the fact that substantial volumes of the Palaeozoic basin fill has been heated to 150 degrees C plus. At lower temperatures experienced further from the contacts between the intrusions and the country rocks, organic matter thermal maturation levels may significantly exceed those related to burial alone. Water-mineral-hydrocarbon interactions in association with magmatic heating have produced a range of effects, including the generation of hydrocarbons rich in sulphur compounds such as mercaptans.
The South Kyrtayel Oilfield, Timan-Pechora basin; geological history and preliminary development plan
Authors: Banks N. L. , de Boer E. T. , Scott J. M. , Sheptunov A.
Published: November 2010

The South Kyrtayel oilfield lies on the western margin of the Pechora-Kozhva Swell, a major inverted Palaeozoic rift element of the Timan- Pechora basin. The field was discovered in 1976 but is only now being developed by Bitech-Silur who obtained a licence over it in 1995. Like many fields nearby, the South Kyrtayel field contains modest volumes of oil and gas in Middle Devonian sandstones capped by Upper Devonian shales: current estimates of hydrocarbons in-place are 70 MMBBLS of oil and 70 BCF of gas. The fluviatile and near-shore marine Middle Devonian reservoir sandstones were deposited in a rift basin. The trap is an anticlinal structure bounded by a north-south trending fault. The trap developed in the Devonian and was modified during the Carboniferous to Jurassic. There has been considerable uplift of the field since maximum burial and oil charge in the Triassic.
The geological selection of drilling fluids in horizontal wells
Authors: Hillier Iain
Published: November 2010

The drilling of horizontal wells has led to new demands on drilling fluid design. Less damaging drill-in fluids are formulated after extensive geological testing of the productive formation. This paper describes the main tests undertaken and some of the fluids commercially available. Geological analysis of the formation is followed by the testing of a proposed fluid, including extended exposures of the formation and fluid in conditions imitating those found downhole. Potential production impact is assessed by a return permeability test. With a clear understanding of what causes formation damage, drill-in fluid chemistry and properties can be engineered to prevent damage. Glycol, formate and sized calcium carbonate particle technologies are described.
Uncertainty estimation in volumetrics for supporting hydrocarbon exploration and production decision-making
Authors: Floris Frans J. T. , Peersmann Martin R. H. E.
Published: November 2010

A methodology is presented for uncertainty estimation in volumetrics. Firstly, we stress the need for an open hierarchical methodology. This allows for a flexible work process in estimating uncertainty throughout the asset life cycle, in which data of various scales and accuracy must be integrated. Secondly, a method is explained for the transfer of spatial uncertainty in structure and rock properties to uncertainty in hydrocarbon volume. Thirdly, a new technique is presented for calculating average water saturation. Application to a synthetic case study shows that scalar uncertainty calculation leads to an underestimation of the uncertainty compared to a spatial approach. Spatial mapping of standard deviation of net hydrocarbon column indicates extra potential in the field. Incorporation of correlations in the field between, for example, porosity, permeability and water saturation, increases the uncertainty range. Using extra wells in the uncertainty estimation reduces uncertainty. Now, the known volume lies within the estimated proven-to-probable range.
Integrated whole-rock trace element geochemistry and heavy mineral chemistry studies; aids to the correlation of continental red-bed reservoirs in the Beryl Field, UK North Sea
Authors: Preston J. , Hartley A. , Hole M. , Buck S. , Bond J. , Mange M. , Still J.
Published: November 2010

Correlating continental red-bed successions in the sub-surface is a common problem for the hydrocarbon industry. These successions are typically barren of fauna and often monotonous, leading to non-diagnostic wire-line log signatures. A high-resolution, high precision study of detrital garnet chemistry within Triassic reservoir sandstones from the Beryl Field of the North Sea failed to subdivide the sequence satisfactorily. However, the whole-rock concentrations of immobile trace elements such as Zr, Nb and Cr can be shown to be controlled primarily by the abundances of the heavy minerals zircon, rutile and chrome-spinel, respectively. The chemistry of detrital rutile and chrome spinel varies widely within any one sample, implying that the whole-rock concentrations of Nb and Cr are also a function of the chemistry of these heavy minerals. Having calibrated a type well with a detailed mineralogical and geochemical study, it was possible to correlate between wells using whole-rock geochemical cross-plots.
The role of faults in hydrocarbon migration
Authors: Moretti Isabelle
Published: November 2010

It is well known that the hydrodynamic behaviour of faults may be rather different from that of their surrounding beds. These characteristics may not be constant through time for a single fault and especially change during rupture events. Various numerical tests were performed using the TEMISPACK software to calculate the quantity of hydrocarbons that can migrate through damaged zones with high permeability in and near to a fault. The paper examines the influence on fluid flow of (1) the thickness of the fault zone, (2) the connectivity between fault and carrier beds, and (3) the opening time when permeability increases sporadically. The results confirm the importance of fault zones on hydrocarbon migration. Even when very narrow (2 meters), temporarily open (<100000 years), and moderately permeable (<10 mD), faults focus the migration of hydrocarbons. The flow is stronger in narrow, temporary faults but the quantities in circulation remain essentially the same. The nodes of the migration paths are the connections between faults and carrier beds (and/or source rock). This connection has a greater influence on the quantity of migrating hydrocarbons than does the intrinsic permeability of the fault. Given major hydrocarbon losses in the rock's porosity, thick drains are less efficient than are narrow zones for bringing the hydrocarbons to the reservoirs.
Fluid dynamic aspects of oil migration and accumulation in the northeast of the Timan-Pechora Basin
Authors: Lodzhevskaya M. I. , Smolenchuk T. N.
Published: November 2010

An analysis of the formation and distribution of oil pools within the Varandey-Adz'va Zone in the northeast of the Timan-Pechora Basin has revealed differing patterns of oil migration and accumulation in various parts of the area. Oil fields in the north and centre of the Sorokina Swell and in the Gamburtseva Swell are reservoired over a wide stratigraphic ranger: from the Triassic through the Lower Devonian. This suggests the possibility of uninterrupted upward transit of fluids from lower stratigraphic levels (Ordovician-Lower Devonian). The oils found in the Upper Devonian at the Saremboy-Lekkeyaga Swell and in the south of the Sorokina Swell are syngenetic, mixed with oils brought by inflow from underlying strata. Oils in the other complexes are epigenetic. Triassic through Lower Permian strata have not yet entered the main oil window and cannot be the sources of commercial hydrocarbons.
Can oil emplacement prevent quartz cementation in sandstones?
Authors: Worden Richard H. , Oxtoby Norman H. , Smalley P. Craig
Published: November 2010

In the current debate on the ability of oil emplacement to halt quartz cementation in sandstone oil reservoirs, this paper supports a "yes, it can" answer. Although we find some of the empirical data petroleum fluid inclusion abundances, quartz-depth trends) to be inconclusive, we have made progress in this debate by examining theoretical controls for three end-member quartz cementation scenarios. (1) Silica externally sourced via advection. Oil emplacement must halt quartz cementation because of the associated massive reduction in relative permeability to water. (2) Silica supplied internally, water-wet reservoir. Quartz cementation will be inhibited because the rate of diffusion will be reduced by orders of magnitude, making diffusion the rate controlling step. The degree of inhibition will depend on rock fabric and oil saturation; at very high oil saturations quartz cementation could effectively cease. (3) Silica supplied internally, oil-wet reservoir. Quartz cementation will be halted as water cannot access to grain surfaces.
Non-hydrocarbon components of Carboniferous-sourced gas in the Southern Permian Basin, northwest Europe
Authors: Gras R. , Clayton C. J.
Published: November 2010

Natural gas sourced from Carboniferous coal-bearing strata is produced from Carboniferous, Permian and Triassic reservoirs in the Southern Permian Basin in northwest Europe. The composition of this gas has been reviewed. In all reservoirs a distinct area rich in non-hydrocarbons, principally nitrogen, coincides with the basin depocentre in northern Germany. Furthermore, the average nitrogen concentration increases upwards in the stratigraphy. Carbon dioxide is a minor component which is geographically restricted and occurs mainly in Carboniferous and Zechstein reservoirs. It is generated indigenously in these reservoirs and does not migrate into other reservoirs. Hydrogen sulphide occurs only significantly in the Zechstein and is areally restricted to the basin margin facies of this reservoir. It is formed by thermochemical sulphate reduction. The maturity of the source rock, timing of the trap formation relative to the gas source maturation and reservoir lithology appear to be the dominant controls on the non-hydrocarbon gas composition in the Southern Permian Basin. For very high nitrogen gases (50-100 vol. %), an admixture of inorganic nitrogen to the thermogenic gas from organic sources cannot be excluded.
Estimation of ultimate recovery for UK oil fields; the results of the DTI questionnaire and a historical analysis
Authors: Thomas J. M.
Published: November 2010

The UK Department of Trade & Industry (DTI) recently sent out a questionnaire (see Appendix) to North Sea operating oil companies to survey the different methods used in the estimation of ultimate hydrocarbon recovery and production forecasting. The feedback revealed significant differences in approach between operators in estimation methods and also a wide range of perceptions of the value and accuracy of ultimate recovery and production forecasts. This paper reports the findings of the survey and also takes a historical look at how accurate ultimate recovery estimates have actually been for UK Continental Shelf oil fields developed over the last decade. Historical reserves estimates have been rather inaccurate, with many fields exhibiting changes in estimated ultimate recovery over a ten-year period of over 50%. These inaccuracies have had a severe effect on facilities requirements for many large North Sea fields. The fields studied have required an average of 60-80% more wells than anticipated at the time of Development Plan submission and up to 400% average increase in platform water handling capacities has been necessary. Average field lifetimes have been over a decade longer than originally expected. Accommodating unexpected changes of this magnitude within existing offshore facilities has proven a very expensive exercise and we therefore suggest there is a need for a more unified approach by the industry to ultimate reserves estimation.
Physical constraints on hydrocarbon leakage and trapping revisited
Authors: Bjorkum Per Arne , Walderhaug Olav , Nadeau Paul H.
Published: November 2010

In a water-wet petroleum reservoir with a water-wet seal, a continuous water phase will extend from the reservoir into the seal, and the pressure difference between the water phase in the uppermost pores of the reservoir and the water phase in the lowermost pores of the seal can therefore only be of an infinitesimal magnitude. This implies that any overpressure in a water-wet reservoir will not contribute to pushing the hydrocarbons through a water-wet seal, and overpressured water-wet reservoirs should therefore not be considered more prone to capillary leakage than normally pressured reservoirs. Within a water-wet petroleum reservoirs, the overpressure in the hydrocarbon phase relative to the water phase is balanced by the elastic forces at the fluid interface (interfacial tension). The overpressure in the hydrocarbon phase relative to the water phase therefore does not increase the risk of hydrofracturing the reservoir's seal. This implies that the risk of hydrofracturing should not be increased as a function of hydrocarbon column height, and should not be considered to be higher for gas than it is for oil. When an upward-directed hydraulic gradient is present from a reservoir unit into the overlying seal, water will continuously move upwards from the reservoir unit and into the seal if both rocks are water-wet. This movement of water may lead to exsolution of gas above the reservoir unit, and the presence of free gas may be detected as gas chimneys on seismic sections. This mechanism will operate regardless of whether or not a hydrocarbon accumulation is present below the gas chimneys, and fracturing of the reservoir unit's seal or capillary leakage of hydrocarbons are therefore not necessary conditions for the development of gas chimneys.
Representation and scaling of faults in fluid flow models
Authors: Walsh J. J. , Watterson J. , Heath A. E. , Childs C.
Published: November 2010

Fault representation and scaling in flow models are examined with respect to fault zone properties, the accuracy with which they can be determined, and how these variables and fault geometries can be incorporated realistically in to flow models. Outcrop data show that fault displacement/thickness ratios and permeability vary widely. For simple single fault models, results for numerical models are compared with analytical and statistical methods. Representation of a fault as a transmissibility surface conflates the effects of four variables--fault zone thickness and permeability, grid-block size and matrix (host-rock) cell permeability. Random spatial variation of transmissibility factor values is well represented by a uniform transmissibility factor which is the arithmetic mean of the values representing log-normally distributed permeability and thicknesses. Realistic ranges of fault zone thicknesses can be represented without grid-block refinement by an upscaling method based on simple transformation of transmissibility factor curves derived from a range of coarse grid-block models. Sub-seismic faults have significant effects on effective permeability of model volumes at kilometre scales only when the faults are assigned a permeability less than c. 0.001 of the matrix permeability.
The Bahar oil and gas-condensate field in the South Caspian Basin
Authors: Narimanov A. A. , Akperov N. A. , Abdullaev T. I.
Published: November 2010

The Bahar Field was discovered in 1968 and contains oil and gas-condensate in sandstones and sandy siltstones belonging to the middle Pliocene Productive Series. This has a total thickness of 3600 m. It consists of alternating sandstones, sandy siltstones and shales, with thicknesses between 5 m and 50 m and is of deltaic origin. The reservoir rocks have porosities of 13-18% and permeabilities of 45-250 mD. Biomarker geochemical analyses of onshore and offshore fields show that the Pliocene oil and gas fields in the South Caspian Basin have been charged primarily from epigenetic hydrocarbons. The hydrocarbons have migrated vertically along faults from older source rocks, probably including organic-rich shales of Oligocene to early Miocene age. The Bahar Field is quite mature. Of the original hydrocarbons in place, 72% of the gas has been produced, 39% of the condensate and 11% of the oil. The main oil-bearing horizons, the Pereriv Suite (SP) and Balakhany X, are developed with reservoir pressure maintenance by longitudinal and marginal (up-dip) flooding of surfactant-added sea water.
Biomarker oil-to-source rock correlation in the Western Carpathians and their foreland, Czech Republic
Authors: Picha Frank J. , Peters Kenneth E.
Published: November 2010

Biomarker analyses indicate that at least two petroleum systems operate in the Vienna basin, Carpathian thrust belt and the European foreland plate in Moravia--one associated with Jurassic and the other with Palaeogene organic-rich rocks. Four oils from the sub-Carpathian foreland plate and one sample from the Vienna basin were analysed and geochemically compared to extracts from Jurassic and Palaeogene source rocks. Two oils from the subthrust foreland plate Lubna-18 and Dolni Lomna-1) are genetically related based on similar geochemical compositions. These oils show high oleanane and 24-nordiacholestane ratios, age-related biomarker ratios that are consistent with an origin from Palaeogene organic-rich rocks. These rocks are inferred to be either the Menilitic shales of the Carpathian thrust belt or autochthonous Palaeogene deposits buried below the thrust belt. Two other oils from the subthrust plate (Zdanice-7 and Damborice-16 correlate geochemically with extracts from Jurassic source rocks in the Sedlec-1 and Nemcicky-1 wells. Like the oil extracts, these oils lack oleanane and show low 24-nordiacholestane ratios, supporting an origin from Jurassic organic-rich marls. The oil sample from the Vienna basin (Tynec-34) appears to be a mixture of the two oil groups.
Rejuvenating marginal, aging oil fields; is it profitable?
Authors: Sneider Robert M. , Sneider John S.
Published: November 2010

Small multidisciplinary geoscience-engineering teams of 5 to 10 professionals searched for large volumes of low risk reserves in poorly performing oil fields. Between 1981-1996 over 350 mature fields in the Permian and Gulf of Mexico basins were scanned looking for fields to purchase. Forty-six fields were purchased. The purchased fields include those producing by (1) primary recovery without secondary recovery potential, (2) primary recovery with supplemental recovery potential and (3) those undergoing waterflooding. Finding large volumes of low risk, presently non-producing reserves within fields involves several steps. First, the team searches in reservoir systems that appear more massive and homogeneous than they are. Second, the team scans the geoscience and engineering data to quickly estimate original oil-in-place, percent recovery, remaining reserves and potential bypassed reserves. Third, the team makes an economic analysis including recovery cost estimates for the volume of missed low and high-risk reserves. Candidate fields for purchase all have new low to moderate risk reserves amounting to at least 5% of the cumulative reserves already produced. Forty-one fields are economically successful with an after-tax rate of return (ATROR) of 12 to 41% (average 21%) and three fields made 5-7% ATROR. Two fields are economic failures. Payout for the 44 economically successful fields ranged from 11 months to 5.8 years.
Temperature and heat flow in the Celtic Sea basins
Authors: Corry Dympna , Brown Colin
Published: November 2010

Hydrocarbon exploration wells provide sufficient information to analyse the present-day thermal regime in the Celtic Sea basins. This information consists of bottom hole temperatures (BHTs), geophysical well logs, composite logs and rock cuttings from the major formations. The BHTs provide numerous but low-quality data which require extensive processing before they provide reliable estimates of formation temperature. Standard corrections (Horner plots) to multiple BHTs can be modified to correct single BHT measurements. A least-squares inversion based on a thermal resistance (Bullard) model for conductive heat flow can map many noisy Horner-corrected BHTs into a set of formation temperature estimates with relatively small errors. The average geothermal gradient is 32 degrees C km (super -1) . Laboratory measurements of the thermal conductivity of rock cuttings taken from representative formations in selected wells give matrix conductivities at room temperature. These sample measurements are combined with information about formation porosity and temperature to give in situ thermal conductivities for each formation in each well. These are then used with formation temperature gradients from the BHT analysis to estimate heat flow. The heat flow obtained for the Celtic Sea basins varies between 59 and 81 mW m (super -2) . The highest values appear to be where sediments are thickest.
2D flexural backstripping of extensional basins; the need for a sideways glance
Authors: Roberts Alan M. , Kusznir Nick J. , Yielding Graham , Styles Peter
Published: November 2010

Backstripping is a technique employed to analyse the subsidence history of extensional basins, and involves the progressive removal of sediment loads, incorporating the isostatic and sediment decompaction responses to this unloading. The results of backstripping calculations using 1D models employing local (Airy) isostasy and 2D models employing "flexural" isostasy are compared for three cross-sections of the North Sea rift basin. Backstripping is commonly used to estimate stretching factor (beta ) across extensional basins. At structural highs 1D Airy backstripping will overestimate beta by comparison with predictions from 2D flexural backstripping, because Airy isostasy fails to acknowledge the effects of lateral differential loading. Predictions of beta from 2D flexural backstripping are closer to those derived from forward modelling. 1D Airy backstripping also produces unrealistic internal deformation of individual fault-blocks and overestimates beta when the pre-rift sequence is not fully decompacted. The palaeobathymetric data required by 1D Airy backstripping are often inaccurate, which yields misleading results. 2D flexural backstripping has been formulated as reverse post-rift modelling, which is used to produce sequential (isostatically balanced) palinspastic post-rift cross-sections. These are calibrated using only high-quality palaeobathymetric data, allowing 2D flexural backstripping to be used to predict palaeobathymetry away from the calibration points.
The petroleum systems of the Pechora Platform Foreland, Russia
Authors: Martirosyan V. , Popova L. , Vepreva M.
Published: November 2010

The Timan-Pechora hydrocarbon basin is one of the most petroliferous provinces of Russia. It is at a mature stage of exploration onshore but is still poorly explored offshore. The exploration within the offshore extension of the Pechora Platform commenced in 1988 and has resulted in five commercial discoveries of oil and gas/condensate, the Severo-Gulyaevskoye, Pomorskoye, Prirazlomnoye, Varandey-More and Medyn-More fields. Hydrocarbon accumulations within the offshore extension of the Pechora Platform are related to at least two petroleum systems: the Domanik-Permo-Carboniferous and the Silurian-Lower Devonian. Reservoir rocks range from the Lower Devonian to the Upper Permian and are mostly carbonates. Throughout the onshore area of the Pechora Platform, Silurian-Lower Devonian formations and Domanik shales are known as the main source rocks. This paper concerns the easternmost petroleum systems of the Pechora Platform that stretch west of the Novaya Zemlya Orogen and encompass more than 100 oil and gas fields.
Structure of the East Shetland Platform, northern North Sea
Authors: Platt Nigel H. , Cartwright Joseph A.
Published: November 2010

The East Shetland Platform formed a regional high throughout the Mesozoic and Tertiary with only a thin Triassic to Recent succession preserved. Seismic data reveal the underlying structure and stratigraphy. Complex seismic reflections are seen within the basement and may indicate basement thrust duplexes and lateral ramps, recording Caledonide deformation. A distinctive change in seismic character, traceable over the entire area, marks the base of a sedimentary package >7.5 km thick which overlies and locally onlaps a regionally persistent top basement reflector. This package is thought to be Devonian. The recognition of several internal discontinuities within it may permit subdivision into tectono-stratigraphic units. Local divergence of the reflectors within the Devonian succession provides evidence of syn-sedimentary growth faulting, perhaps due to extension in the hanging wall of reactivating, rolled back Caledonide thrust faults. The Devonian sequence is locally deformed into symmetrical to eastward-vergent folds, these marking a pre-Mesozoic compressional deformation phase of probable Variscan age. The Devonian strata on the East Shetland Platform may provide local hydrocarbon charge from oil-prone lacustrine source rocks, as well as fluvial sandstones with moderate reservoir potential. Dipping and locally intensely folded Devonian strata can offer a range of structural and stratigraphic traps in this poorly explored area.
Organic geochemistry of the Cenomanian-Turonian sequence in the Bakr area, Gulf of Suez, Egypt
Authors: Mostafa Alaa R.
Published: November 2010

The Cenomanian-Turonian transgression has been studied in a 220 m cored section using common source rock data, elemental data and conventional biomarker parameters. Differences in the type of organic matter found in these regressive and transgressive offshore marine sediments have been documented and assessed within a sequence stratigraphic framework. The interval of maximum flooding of the Cretaceous seaway shoreline is delineated by discontinuities in the total organic carbon content and Hydrogen Index. The overall transgressive event is also accompanied by (a) an increase in the concentrations of elements such as thorium, vanadium, potassium, barium, sodium...etc., (b) changes in the relative concentrations and the characteristics of the biomarker parameters and (c) changes in the characteristic features of the kerogen. All of these data are consistent with a simultaneous decrease in terrigenous organic matter and increase in marine algal input.
Fault transmissibility multipliers for flow simulation models
Authors: Manzocchi T. , Walsh J. J. , Nell P. , Yielding G.
Published: November 2010

Fault zone properties are incorporated in production flow simulators using transmissibility multipliers. These are a function of properties of the fault zone and of the grid-blocks to which they are assigned. Consideration of the geological factors influencing the content of fault zones allows construction of high resolution, geologically driven, fault transmissibility models. Median values of fault permeability and thickness are predicted empirically from petrophysical and geometrical details of the reservoir model. A simple analytical up-scaling scheme is used to incorporate the influence of likely small-scale fault zone heterogeneity. Fine-scale numerical modelling indicates that variability in fault zone permeability and thickness should not be considered separately, and that the most diagnostic measure of flow through a heterogeneous fault is the arithmetic average of the permeability to thickness ratio. The flow segregation through heterogeneous faults predicted analytically is closely, but not precisely, matched by numerical results. Identical faults have different equivalent permeabilities which depend, in part, on characteristics of the permeability field in which they are contained.
Wettability heterogeneities in gas injection; experiments and modelling
Authors: Laroche C. , Vizika O. , Kalaydjian F.
Published: November 2010

We carried out experiments to study the effect of wettability heterogeneities on: (1) displacement mechanisms, (2) sweep efficiency and (3) trapped oil quantities and fluid distribution in three-phase gas injection and developed a theoretical simulator. Secondary gas injection experiments was conducted in transparent glass micromodels of heterogeneous wettability. Oil-wet patches in a water-wet matrix were obtained by selective silane grafting on the glass surface. Different heterogeneity patterns were considered for the same oil-wet over water-wet surface ratio. Displacement sequences were video-recorded and fluid saturations determined by image analysis. A theoretical model of three-phase flow in a porous structure was developed. In this model the porous medium is simulated as a network of interconnected pores. The model permits an imposition of heterogeneous wettability by assigning different water-oil contact angles according to the desired wettability pattern. The calculation of flow within the network takes into account the flow of oil through wetting and spreading films and the displacement mechanisms observed in the transparent micromodels. Comparison between experimental results and simulations shows that the size and distribution of wettability heterogeneities strongly affects microscopic and macroscopic behaviour during gas injection.
Organic facies of the Middle Jurassic of the Inner Hebrides, Scotland
Authors: Vincent Alastair J. , Tyson Richard V.
Published: November 2010

An integrated optical (palynofacies) and bulk organic geochemical study has been undertaken in order to determine the controls on the organic facies of paralic Middle Jurassic Hebridean sediments. The total organic carbon (TOC) values are generally between 0.5 and 2.5%, but reach up to 3-4% in dark-coloured non-bioturbated shales within the Bearreraig Sandstone Formation and Lealt Shales Formation, and 6-8% in the Staffin Bay Formation. Hydrogen indices (HI) are mostly below 300, increasing to 400-500 in the aforementioned organic-rich intervals, and reaching 650-800 in the Kilmaluag Formation. The best overall source potential probably occurs in the brackish Lealt Shales Formation. Correlations between HI, TOC and the content of the freshwater alga Botryococcus (< or =9% of the kerogen), suggest that freshwater run-off may have led to stratification of the Middle Jurassic lagoons, and thus dysoxic-anoxic bottomwaters and better quantitative and qualitative preservation of the plankton-derived amorphous organic matter.
Reservoir damage around faults; outcrop examples from the Suez Rift
Authors: Beach Alastair , Welbon Alastair I. , Brockbank Paul J. , McCallum Jean E.
Published: November 2010

Field observations in western Sinai show that damage zones around faults are characterized by (a) a decrease in the frequency of small-scale structures with increasing distance from the master fault, (b) clustering of these structures across damage zones, and (c) a positive relationship between damage zone width and master fault throw in logarithmic space, up to maximum width of about 80 m. This relationship allows damage zone width to be estimated from fault throw, a parameter obtainable from seismic data. Preliminary data on the interconnectivity of structures within damage zones indicate that granulation seams are more likely to intersect than tip out. The thicknesses of small-scale structures were measured, and the cumulative thicknesses of all small-scale structures within individual damage zones calculated. In the examples given, these cumulative thicknesses are up to 1 m within 10-30 m wide damage zones, implying that as much as 1 m of deformed rock, most likely with reduced porosity and permeability, occurs across damage zones. This, together with the interconnectivity data, suggests that the impact of faults on fluid flow may occur not only at fault planes, but throughout their damage zones.
Crustal structure east of the Faroe Islands; mapping sub-basalt sediments using wide-angle seismic data
Authors: Richard K. R. , White R. S. , England R. W. , Fruehn J.
Published: November 2010

We use normal-incidence and wide-angle seismic data recorded on the Faroe Islands to study the crustal structure along two profiles extending east from the islands, across the Faroe shelf and into the Faroe-Shetland Basin. We show that massive basaltic lava flows extend eastward away from the Faroe Islands, having flowed across an older Mesozoic and early Paleocene sedimentary basin, and feathering out near the centre of the Faroe-Shetland Basin. Sediments beneath the basalts reach a thickness of several kilometres in the basin, but do not extend with a resolvable thickness beneath the Faroe Islands. The crustal thickness decreases toward the centre of the Faroe-Shetland Basin, showing that the basement beneath the centre of the basin has been stretched and thinned by a factor of at least two. The Faroe Islands themselves lie on a continental fragment, which had a total thickness of about 10-15 km of igneous rock added as extrusive lavas at the top, and as high-velocity intrusives near the base of the crust at the time of continental break-up in the Paleocene.
An experimental and numerical study of polymer action on relative permeability and capillary pressure
Authors: Barreau P. , Lasseux D. , Bertin H. , Glenat P. , Zaitoun A.
Published: November 2010

Unsteady state two-phase flow experiments were performed to check the action of an adsorbed water-soluble polymer on relative permeability and capillary pressure. A selective reduction of the relative permeability to water with respect to relative permeability to oil was observed. Capillary pressure, measured directly on the core, was increased after polymer injection. Since the polymer has little influence on interfacial tension, this trend is interpreted as a reduction of pore size due to polymer adsorption. The validity of this assumption was checked by the investigation of a pore-scale numerical model. Relative permeabilities and capillary pressure were computed for a range of flow rates. Numerical results indicated that the polymer adsorption model (wall effect) successfully reproduces qualitatively the experimental observations.
A tectonostratigraphic framework for the Statfjord Field, northern North Sea
Authors: Hesthammer Jonny , Jourdan Charles A. , Nielsen Peter E. , Ekern Tor E. , Gibbons Kathryn A.
Published: November 2010

Based on detailed analyses of seismic and well data, the Statfjord Field, northern North Sea, can be separated into a relatively undeformed main field area and an east flank heavily deformed by rotational block slides. The main tectonic event is related to the opening of the Viking Graben which started in the middle Jurassic and which increasingly affected deposition of the Bathonian-Oxfordian Heather Formation. This rift phase peaked before the deposition of the Draupne Formation causing gravitational instabilities along the crest of the field and subsequent rotational block slides in the Upper Triassic and Jurassic sections. Compared to fields closer to the graben centre only limited erosion affected the Statfjord Field reservoirs during the Oxfordian-Ryazanian. Here, the Draupne Formation still drapes a partly degraded Jurassic sequence and is thickest on the west flank and within topographic depressions on the east flank. Minor tectonic activity occurred during the Cretaceous and Tertiary.
Seismic interpretation of circular geological structures
Authors: Stewart S. A.
Published: November 2010

3D seismic data provide images of geological features which are approximately circular in plan view but whose shape and origin may not be possible to constrain using 2D seismic data. As 3D seismic data become more commonly employed in hydrocarbon exploration, the number of demonstrably "circular" structures will increase. At least ten different geological processes can result in seismically resolvable "circular" structures in sedimentary basins. These include salt/shale diapirs, salt withdrawal basins, polygonal fault blocks, dissolution collapse hollows, breccia pipes, calderas, gas pockmarks, bioherms, sand volcanoes, pull-aparts, impact craters and tectonic folds. Geometrical and geological criteria for each are summarized to facilitate identification of such features should they be encountered in the course of a 3D seismic interpretation. Certain types of geological feature have distinctive properties, others are less straightforward to recognize on the basis of individual criteria.
Solution and upscaling of compositional and immiscible displacements in composite media
Authors: Subramanian Sathish K. , Johns Russell T. , Dindoruk Birol
Published: November 2010

The scale of heterogeneities in reservoirs is often smaller than the grid size used in large-scale reservoir simulations. Relative permeabilities have the foremost effect on fluid flow and small-scale fractional flow must be upscaled to the grid size in flow simulations. Thus, systems with fractional flow heterogeneities, i.e. relative permeability variations, have to be solved and effective relative permeability functions determined. In this paper, benchmark analytical solutions are developed for a system consisting of two media in series where each medium is characterized with a different set of relative permeabilities, residual saturations and porosities. The analytical solutions show a significant discontinuity in the saturation and concentration profiles at the interface of the two media. Numerical results using several weighting schemes are compared against the analytical solutions for two-phase immiscible and partially miscible systems. It is shown that single-point upstream weighting requires about 100 grid blocks to capture the discontinuity at the interface, whereas third-order TVD weighting requires much fewer. Lastly, the validity of the JBN method and harmonic averaging for determination of effective relative permeabilities and overall pressure drop is tested. Both the JBN method and harmonic averaging cannot reproduce the pressure drop across the composite media prior to water breakthrough.
Nd and Sr isotopes as clastic provenance indicators in the Upper Carboniferous of Britain
Authors: Leng M. J. , Glover B. W. , Chisholm J. I.
Published: November 2010

Nd-Sr data indicate that two isotopically distinct terrains supplied sediment to the Upper Carboniferous basins of Britain. One terrain was relatively depleted in radiogenic Nd, and included large areas of old continental crust; the other was less depleted in radiogenic Nd and is thought to have included a significant amount of first generation juvenile material that was added to the older crust during the early Palaeozoic continental collisions. The isotopic signatures reflect the average composition of the crust from which the Carboniferous sediments were originally derived. In multicyclic, multiorogenic settings such as NW Europe, understanding the geographic distribution patterns of the sediment can only be accurately ascertained by employing a combination of provenance characterizing techniques (isotopes/palaeocurrents/heavy minerals). Here, combined results indicate that the first terrain lay in Laurentia, whereas the other was a large region bordering the north side of Gondwana, and including Avalonia and Armorica.
Detailed morphology of the Top Chalk surface in the eastern Danish North Sea
Authors: Huuse Mads
Published: November 2010

A detailed time-structure map of Top Chalk in the eastern Danish North Sea is presented, based on conventional seismic and well data, and 5800 km of new multi-channel, high resolution seismic data. Several factors influenced the present-day topography of Top Chalk at various scales: Cenozoic regional differential subsidence/uplift, reactivation of late Palaeozoic-Mesozoic structures, salt structures in the Norwegian-Danish Basin, collapse structures along the Ringkobing-Fyn High, mounds on the Ringkobing-Fyn High, erosional valleys, and possible karstification in parts of the Norwegian-Danish Basin. Erosional valleys and karst topography suggest that the Top Chalk was subaerially exposed in the eastern North Sea in mid-Paleocene times. The valleys probably acted as conduits for deposition of potential reservoir sands in the middle to late Paleocene. The interpretation of karst topography indicates that carbonate dissolution may have affected the reservoir properties of the uppermost part of the Chalk Group in the eastern North Sea.
Assessing the anisotropic permeability of Glossifungites surfaces
Authors: Gingras Murray K. , Pemberton S. George , Mendoza Carl A. , Henk Floyd
Published: November 2010

The potential permeability enhancement of a substrate that has been burrowed by a suite of fauna that inhabit geological firmgrounds (i.e. the Glossifungites ichnofacies) is investigated by using computer simulations, laboratory and field measurements to assess the effective permeability of a Pleistocene Glossifungites surface. All the testing methods indicate that the effective permeability of a substrate is markedly enhanced by the presence of sand-filled Glossifungites burrows in the low-permeability substrate. Furthermore, the permeability of these burrowed horizons can be well approximated by using a modified arithmetic mean that accounts for the degree of interconnectivity between burrows. These formulae are robust and, conceptually at least, can be applied to a variety of geological media and burrow configurations.