bluuebunny/crossref_metadata_2025 huggingface dataset:
Building conceptual structural models from multiple modelling sources; an example from thrust-ramp studies
Authors: Patton T. L. , Serra S. , Humphreys R. J. , Nelson R. A.
Published: November 2010

In the interpretation of structures from fragmentary subsurface geological data, the modelling attribute most commonly employed is that of model geometry or form. Other model attributes can provide insights to exploration-related problems associated with a structure. The nature of these attributes depends on the modelling approach (i.e. materials, boundary conditions, initial conditions); several are unique to a particular approach. The integration of data from several modelling approaches, each aimed at specific attributes, allows the most complete understanding of a structure. This leads to the development ol conceptual models of the origin, evolution and expression of structures as a function of initial conditions and boundary conditions. Such models provide 'rules of thumb' that guide interpretations in structurally complex areas. Laboratory and mathematical modelling attributes have been used here to improve our understanding of the deformation of the hanging wall above a thrust ramp.
2D and 3D analogue modelling of extensional fault structures; templates for seismic interpretation
Authors: McClay K. R.
Published: November 2010

Scaled analogue models of 2D and 3D extensional fault systems provide powerful templates for the seismic interpretation of complex fault structures. 2D sandbox models of extensional faults that link to a lower detachment surface are characterized by roll-over structures together with crestal collapse graben and antithetic fault systems. The geometry of the roll-overs are controlled by the shape of the main detachment surface. 3D extensional fault systems in sandbox models of orthogonal and oblique rift systems are characterized by segmented planar fault systems that grow along strike, link, and overlap forming relay ramp structures and accommodation zones. In orthogonal rifts the border faults and the intra-rift faults are oriented at high angles to the extension direction. In oblique rifts the border faults are parallel to the zone of rifting whereas the intra-rift faults are oriented at a high angle to the extension direction.
Analogue models of salt diapirs and seismic interpretation in the Nordkapp Basin, Norway
Authors: Koyi H. , Talbot C. J. , Torudbakken B. O.
Published: November 2010

Dynamically scaled analogue models with an overburden of cohesive sand and a viscous "salt" layer were deformed in a centrifuge to mimic real salt structures in the Nordkapp Basin. Like their natural prototypes, model diapirs were aligned in rows parallel to the basin margins. In profile, model diapirs were asymmetric, suggesting that the real diapirs will possess asymmetric geometries. Like many of the real salt structures, model diapirs pierced without developing a pillow stage because they rose along basin margin faults which propagated up through the overburden from the basement during thick-skinned extension. Once their overburden was weakened by faulting, differential loading forced model diapirs to rise as long as buoyant material was supplied. Some real salt diapirs initially rose as conformable pillows during the early Triassic, became diapiric during middle Triassic and spread broad overhangs during slow sedimentation in late Triassic and Jurassic times. Later, the overhangs reactivated asymmetrically when buried by Cretaceous and Tertiary sediments.
Recent developments in reservoir engineering and their impact on oil and gas field development
Authors: Davies R. H. , Niko H.
Published: November 2010

With much of the reservoir engineering development activities prior to 1986 being directed to new processes such as EOR, reservoir engineering of today has, like the other petroleum engineering disciplines, become part of an integrated effort to extract the maximum amount of oil from a reservoir. We will discuss some of the new developments in reservoir engineering which had a real impact on oil field operations in Shell and on the working practices of the individual reservoir engineer. Examples of recent advances in reservoir engineering are: (1) progress in the field of measuring residual oil saturations to water under representative conditions which will enable a more realistic assessment of trapped/bypassed oil in water floods such as those in large North Sea fields; (2) improved understanding of the production behaviour of horizontal wells based on analytical and numerical modelling which led to successful applications in Gabon and Oman; (3) advances in our understanding of production in naturally fractured reservoirs which provided the basis for a unique field experiment in the Natih Field in Oman; (4) understanding of the mechanism of fracturing in water injection wells, a process which has large cost-saving potential. The one factor largely responsible for the change in working practices of individual reservoir engineers is the availability of modern integrated IT technology. Moreover, working with uncertainty in a structured way has become routine in a reservoir engineer's work.
Parameter estimation in flexural plate motion; elastic, plastic-elastic and thermo-elastic models applied to the Chukchi Basin, Alaska
Authors: Tang J. , Lerche I.
Published: November 2010

Models are presented of flexural plate basement motion (elastic, plastic-elastic and thermo-elastic) due to: (1) compressive or extensional stress; (2) variation of lithospheric basement density along the flexural plate; (3) spatial variations of plate rigidity; and (4) variations of initial plate angle, hinge point position, plate length, initial end load and plate curvature. A non-linear inverse method determines parameters. Synthetic test results and a case history from the Central Chukchi Basin illustrate the accuracy and resolution of the inversion procedure. The Central Chukchi Basin has an unloaded geometry mainly controlled by a Palaeozoic fault system. Plastic or thermal effects produce a narrow unloaded basin geometry not conforming to the Paleozoic fault distribution or to the isopach map of the Upper Ellesmerian sediments. Inverse elastic model results agree with both the known fault system development (from seismic data) and the direction of the Brooks Range motion.
Kinematics of deformation and petroleum system appraisal in Neogene foreland fold-and-thrust belts
Authors: Roure Francois , Sassi William
Published: November 2010

Foreland fold-and-thrust (FFT) belts are one of the remaining frontiers for hydrocarbon exploration where large discoveries can still be expected. A methodology is described to assess their petroleum potential. Oil generation, migration and trapping history are studied together with structural modelling. Structural reconstructions require the successive use of inverse models to restore geological or seismic sections to their initial, undeformed geometry, and forward models to simulate thrust development with time. The restoration of structural sections to their intermediate geometry, between the onset of compression and their present form, is an aid in reconstructing the burial maturation and diagenetic history of potential source rocks and reservoirs. Erosion and uplift are two competing factors that can delay hydrocarbon generation and must be accounted for in these simulations. Forward modelling is helpful in testing the validity of assumed migration pathways and traps. Complementary ID or 2D models are used to integrate the burial and thermal histories with the kinetic parameters of potential source rocks, providing the timing of oil generation and expulsion, and even simulation of fluid flow and migration processes in areas that are well constrained structurally. Coupling the kinematics of deformation of complex areas (fold-and-thrust belts) with thermal, maturation and expulsion modellings is possible. Future implementations in FFT belts will be required to address such important processes as fluid circulation and hydrocarbon migration, or dewatering and compaction of potential reservoirs. The use of these integrated techniques in regional examples is described in Neogene orogenic belts (Western Alps, Apennines, Outer Carpathians, Eastern Venezuela Basin) to explain the various habitats of oil and gas in FFT belts. Oil-source rock correlations help to identify very distinct productive horizons, either in the allochthon or in the underthrust foreland. Long migration pathways (more than 100 km) are identified during early stages of deformation, with migration of the oil toward the flexural bulge. Shorter migration pathways (10 to 20 km) toward the frontal structures of the fold-and-thrust belt are responsible for late-stage trapping.
Vendian to Cambrian carbonate reservoir types of the Siberian Platform
Authors: Kuznetsov Vitaly G.
Published: November 2010

Three types of carbonate reservoir have been recognized in the central and southern part of the Siberian platform based on their structure, reservoir properties and the type of internal migration: multilayer, massive and single-layer. Facies conditions determined the sedimentation mechanisms: biogenic in normal salinity zones and chemogenic in higher salinity zones. Chemogenic sedimentation produced micritic dolomites and limestones with intercrystalline porosity, smaller pores and low porosity and permeability. Biogenic sedimentation resulted in the formation of large interstices and reservoir properties that are significantly higher. As a result of salinity changes, the reservoir properties of similar facies (shallow water, relatively deep water and reefal) worsen towards the south and southwest.
The origin and distribution of porosity in the Zechsteinkalk (Upper Permian) of Hewett Field, southern North Sea
Authors: Southwood David A. , Hill W. O. R.
Published: November 2010

The Zechsteinkalk of the Hewett Field is characterized by extremely heterogeneous porosity distribution. The two most closely spaced wells (only 200 m apart) show one of the largest differences in average porosity (1.8 to 7.6%). In order to locate future wells and achieve 'reasonable' OGIP estimates, it is therefore necessary to model porosity distribution. Facies type has some influence on porosity development. Tidal flat muds developed at the shoreward margins of shoals have only very low porosity, whereas inter-shoal and main shoal facies have moderate porosity, on average. Extreme porosity variation within facies is caused by differential diagenesis. Porosity has been created by leaching and dolomitization and destroyed by early carbonate cementation and by anhydrite cementation. Anhydrite is volumetrically the most significant, occluding 20% (bulk volume) porosity in many intervals and completely cementing many fractures. The scale of the variability that can be derived from modelling of porosity-affecting diagenetic processes is mostly much greater than that found between closely spaced wells, particularly in the case of anhydrite cementation. In spite of this uncertainty the geological model represents an improvement on simple independent porosity contouring. The gross trends of porosity distribution, defined by the sedimentological model, have helped enhance confidence in a seismic porosity model and have helped with estimates of gas resources.
The Markham Field; UK Blocks 49/5a and 49/10b, Netherlands Block J3b and J6
Authors: Myres J. C. , Jones A. F. , Towart J. M.
Published: November 2010

The Markham Field is a gas accumulation lying within the Southern North Sea and straddling the UK-Netherlands median line. The field is a structural trap comprising a well defined horst in its eastern lobe and a domal feature in the western lobe. The Permian Lower Leman/Slochteren Sandstone reservoir comprises aeolian dune sandstones in the southern part of the field passing northwards and upwards through sabkha deposits into a playa claystone. Diagenesis and reservoir quality are highly dependent on original lithofacies with the aeolian sandstones containing the majority of the net reservoir. The gas, sourced from Carboniferous Coal Measures and sealed by overlying Permian Silverpit claystones, is sweet with 83% methane and a condensate-gas ratio of around 52.2 m
3
/m
3
x 10
6
(9 BBL/ MMSCF). The reservoir is being produced by pressure depletion with wells drilled from two fixed platforms. Recoverable reserves are estimated to be around 19.8 x 109m
3
(700 BCF) of gas.
A complete methodology for reservoir characterization through a 3D high-resolution grid
Authors: Volpi B. , Tannoia G. , Donna G. B. , Bougherara R.
Published: November 2010

An accurate reconstruction of reservoir heterogeneity is an important goal of a reservoir study. The methodology presented here is aimed at providing a complete petrophysical characterization of the reservoir, particularly when the heterogeneity cannot be adequately described using traditional methods. The first phase of the methodology is integrated petrophysical characterization. This is performed by a statistical analysis of log and core data using a 'cluster analysis' algorithm. This allows an objective classification of the reservoir components into homogeneous subsets (lithofacies), each with specific lithological and petrophysical characteristics. The second phase is simulation of the reservoir heterogeneity. Here, the 3D distribution of the lithofacies recognized at the wells is performed consistently with the sedimentological model by means of geostatistical simulations carried out using a high-resolution grid. The porosity and permeability values characterizing each lithofacies are then assigned to the simulated images to obtain a highly detailed 3D petrophysical description of the reservoir.
Towards a unified Kimmeridgian Stage
Authors: Cope John C. W.
Published: November 2010

Considerable confusion exists in the interpretation of the term Kimmeridgian. As the Kimmeridge Clay Formation is the principal source rock in the northern North Sea, this confusion has important implications for geoscientists working there. The source of the confusion is historical, but the introduction of the Bolonian Stage as a local secondary standard stage would result in a Kimmeridgian Stage of uniform length, no matter whether a company preferred to use Volgian or Portlandian as the terminal Jurassic Stage. The resolution of this ambiguity will be welcomed by all.
Predicting well productivity from grain size analysis and logging while drilling
Authors: Hogg Andrew J. C. , Mitchell Alan W. , Young Susan
Published: November 2010

Grain size analysis of drill cuttings and Logging While Drilling (LWD) are used to predict permeability-height (KH) in high-angle wells. In the Sherwood Sandstone reservoir, Wytch Farm Field, permeability is controlled by porosity and grain size. These can be measured using LWD density logs and sieve analysis of cuttings. KH and Productivity Index (PI) are estimated using permeability-bulk density transforms for each grain size class. A PI of 60 ( - 35 / + 120 ) STB/day/psi was predicted for the first extended reach well on Wytch Farm. The initial PI was 100 STB/day/psi. This test result calibrated the model for subsequent wells. The predicted PI of the second well was 42 ( + or - 15 ) STB/day/psi. The initial PI was 40 STB/ day/psi. The KH plot is used to geosteer the well; optimize perforation intervals, and to estimate PI in wells plugged-back for water shut-off.
The development of the North Morecambe gas field, East Irish Sea Basin, UK
Authors: Cowan Greig
Published: November 2010

The North Morecambe Gas Field in the East Irish Sea Basin was discovered by well 110/2-3 in 1976 and contains reserves of over 1TCF. The structure is fault-closed on three sides, and dip-closed to the north. Development is by 10 conventionally deviated high-angle wells, from a not-normally-manned platform, through a dedicated pipeline to a new terminal at Barrow. The Triassic Sherwood Sandstone Group reservoir is composed of sandstones deposited in a semi-arid,fluvial and aeolian setting. Thin, aeolian sandstones dominate flow into the well-bore. Platy illite reduces the permeability by 2-3 orders of magnitude in the lower illite-affected zone of the reservoir. RFT measurements from the first development well proved that the free water level was 25 ft higher than expected, giving a maximum gas column of 975 ft. Re-mapping after drilling has shown that 56% of the GIIP is contained in the high permeability illite-free zone.
A compaction trend for Cretaceous and Tertiary shales on the Norwegian shelf based on sonic transit times
Authors: Hansen Sven
Published: November 2010

Grain densities measured on 74 samples from three wells and the corresponding bulk densities from the density log allowed the porosities of the samples to be determined. These values were used to establish a new relationship between transit time and porosity for Cretaceous and Tertiary shales on the Norwegian Shelf. Normally pressured and compacted Cretaceous and Tertiary shale intervals in 29 carefully selected wells were then identified and shale porosities calculated using the established shale transit time-porosity relationship. Based on these calculated shale porosities, exponential and linear depth-porosity trends are possible.
Structure and hydrocarbon prospects of the North Urals thrust belt
Authors: Sobornov Konstantin O. , Rostovshchikov Vladimir
Published: November 2010

The North Urals thrust belt holds significant hydrocarbon resources hosted mainly in thrust-related anticlines mapped at the surface. New seismic and drilling data have permitted the identification of new exploration targets. The most attractive structural plays are considered to be associated with the buried antiformal stacks in front of the belt. Stacks of folded thrust sheets involve the regionally productive Silurian-Lower Permian carbonates and sandstones encased by thick Artinskian shales, which provide both the source rocks and sealing. Untested structural closures in the buried wedge-shaped thrust sheets are the primary targets for exploration. Additional prospects are predicted in the autochthonous section of the thrust belt. This play includes a subthrust continuation of inverted anticlinal zones of the Pechora-Kolva aulacogen.
Estimating fluid pressure below intrusive salt sheets; the factors causing uncertainty
Authors: Petersen K. , Lerche I. , Lowrie A.
Published: November 2010

In the Gulf of Mexico, uncertainties in salt sheet thickness, lateral salt speed, sub-sea floor depth of salt top, and lithology underlying salt all contribute to the uncertainty in assessing excess pressure development to be expected when drilling through a salt mass. In an example, the mean excess pressure is around 170 atm with + or -30atm uncertainty. The uncertainty in the estimate of excess pressure is shown to be dominated (58-65%) by uncertainties in salt sheet thickness, with salt speed and lithology of lesser importance, each contributing around 10-25% to the excess pressure uncertainty, depending on the case considered. The cumulative probability of obtaining an excess pressure greater than a specified magnitude at any depth is investigated, as is the volatility of estimates on mean pressure. The calculations provide information on which uncertainties-in salt thickness, salt speed or sub-salt lithology-need to be improved first in any attempt to narrow the range of uncertainty of predicted pressure.
A generalized streamline method to predict reservoir flow
Authors: Blunt Martin J. , Liu Kuiran , Thiele Marco R.
Published: November 2010

We present a generalized streamline method to model flow in porous media, including the effects of gravity and dispersion. We first describe the theory and discuss the approximations of the method, and then compare the predictions using the streamline technique against two-dimensional numerical simulations of incompressible miscible flow. In the cases we studied, the streamline method predicts recovery with an average error of at most 5%, where the principal flow directions are governed by the pattern of permeability, and for gravity numbers less than or equal to 1 and mobility ratios of 10 or less. The streamline method does not suffer from numerical dispersion and is more than 100 times faster than conventional simulation.
Laboratory evaluation of a new, selective water control treatment and its implementation in a North Sea well
Authors: Zettlitzer M. , Schuhbauer W. , Kohler N.
Published: November 2010

A new weak gel consisting of a non-ionic, high molecular weight polysaccharide and an organometallic activator was developed for harsh reservoir conditions. A first field application was performed on a candidate well in an oil field in the German North Sea tidelands in June 1992. The treatment had to be designed for the entire range of the perforated interval. The polymer solution was readily injectable and the activator was added to the last quarter of the injected volume. The treatment was considered successful as the initial increased water-cut could be maintained at a level of 65%, the overall production rate being comparable to that before treatment. However, the desired reduction in water production was not achieved, presumably because formation permeability was higher than estimated. A laboratory post-implementation evaluation was conducted to find out whether a possible further treatment with a stronger gel might be feasible. The results indicate that formulations yielding stronger gels would still be selective and easily injectable and would show a far greater water control potential.
The Fife Field, UK central North Sea
Authors: Mackertich David
Published: November 2010

The Fife Field is located in the far southeastern part of the Central North Sea Basin close to the UK, Norwegian, Danish median line. The field is a shallow relief four-way dip closure formed by inversion during Late Cretaceous/ early Tertiary times. The reservoir consists of thick Upper Jurassic, heavily bioturbated sandstones which are considered to have been deposited in a similar setting to the Fulmar Formation. The depth to the top of the Upper Jurassic at the crest of the field is 8250 ft sub-sea with the oil-water contact at 8512 ft sub-sea. The seal to reservoir is provided by Volgian-Ryazanian shales of the Kimmeridge Clay Formation and Upper Cretaceous Chalk. Although Jurassic sandstones form the primary reservoir, additional hydrocarbons have been encountered in the Tor Formation of the Chalk Group which is fractured over the crest of the field. The Fife Field was discovered in 1991 and is currently under development. Production started in August 1995 via the 'Uisge Gorm' Floating Production Storage and Offloading facility (FPSO). STOIIP is estimated at 132 x 106BBL and ultimate recovery is predicted to be 34 x 106 BBL oil. The low mobility of the oil and the low vertical permeability of the reservoir contribute to the predicted low (26%) recovery efficiencies.
Geoscore; a method for quantifying uncertainty in field reserve estimates
Authors: Dromgoole P. , Speers R.
Published: November 2010

The field reserves evaluation strategy developed in this paper is a tool to help recognize and quantify the key uncertainties in field reserve estimates before committing to development. Reserve estimate changes through time for UKCS fields developed over the last 20 years are examined. We examine the causes of these changes and propose a scheme to assess fields in terms of structural complexity and reservoir quality and architecture using nine categories. Applying this scheme, termed "Geoscore", to 33 UKCS fields we show that reserve estimates: (a) for low complexity (low Geoscore) fields are underestimated by an average of 20%; (b) for medium complexity fields are overestimated by 10%; (c) for high complexity (high Geoscore) fields are overestimated by 15%. There is also a trend of decreasing recovery factor with increasing Geoscore. Accurate reserve estimation during field appraisal requires: recognizing the key uncertainties; quantifying the relative importance of these uncertainties; either collecting data or preparing contingency plans to handle potential problems that may arise during field development. We describe the key uncertainties, types of data to be collected and how to handle the remaining uncertainties. Careful application of the Geoscore analysis helps the recognition and quantification of these key uncertainties.
Seismic attribute analysis in structural interpretation of the Gullfaks Field, northern North Sea
Authors: Hesthammer Jonny , Fossen Haakon
Published: November 2010

Seismic attribute maps provide a useful tool in interpreting faults, particularly those close to or below seismic resolution. Dip, relief, azimuth and amplitude maps are most useful. Optimal use of such maps requires careful filtering and appropriate use of colours and light sources. One of the challenges is to distinguish between anomalies related to real geological features and to seismic noise--both of which may occur as linear or curvi-linear, continuous features on the attribute maps. This challenge must be solved by use of independent data. In the North Sea Gullfaks Field, a family of (curvi-)linear features on the attribute maps are subparallel to contour lines on time maps. Core data, dipmeter data, stratigraphic log correlation and forward modelling show that these features are related to seismic noise rather than real faults.
Integrated of inclined pilot hole core with horizontal image logs to appraise an aeolian reservoir, Auk Field, central North Sea
Authors: Follows E.
Published: November 2010

An inclined appraisal well, 30/16-13, drilled in 1992-3 in the north of the Auk Rotliegend oil field, Central North Sea confirmed sufficient gross rock volume to justify a horizontal appraisal/development sidetrack 30/16-13S1 to assess the viability of a horizontal well development for Auk North. Close proximity of the two wells provided an opportunity for an integrated reservoir description. Core over the entire 125 m reservoir section of 30/16-13 was orientated, and tied to dipmeter data, later reprocessed into image logs. These data, plus conventional log responses, enabled a threefold subdivision of the aeolian facies including dune slipface sandstones. The sidetrack was horizontally geosteered through 625 m of reservoir, maintaining a stand-off above the field-wide free water level, and beneath the dipping Top Rotliegend structure unconformity. Careful selection of the optimal azimuth for the horizontal well track to pass up stratigraphic section maximized the number of slipface intervals encountered and preferential permeability pathways to the wellbore. Formation MicroImager (FMI) logs in the horizontal well, calibrated with core and logs from the inclined hole, enabled the characterization of the lithofacies, faults and fractures, including orientations. This detailed reservoir characterization was much greater than could be expected from either hole.
Constraints on hydrocarbon migration from the Qingshahou source rock in the west of the North Shongliao Basin, China
Authors: Pang X. , Lerche I.
Published: November 2010

Many small gas fields have been discovered in the west of North Shongliao Basin of China while drilling for oil. Applications and results of DTIT and GEOPET II codes indicate that the formation and distribution of these gas fields are controlled by hydrocarbon expulsion and migration from the major Qingshahou source rock. This generated most of the oil and gas at 88-50 Ma and 50-0 Ma, respectively; the ratio of oil to gas is about 70:30. Most of the separate-phase oil was expelled at 35-15 Ma, but no separate-phase gas was expelled because of total solution of generated gas in oil and in connate water. Gas dissolved in water tended to migrate from the deep source rock centre to the West Slope (shallower formations) of the basin through sandstone reservoirs and normal faults, gradually being released from solution and accumulated in traps along the migration route. Gas dissolved in oil tended to migrate to traps around the source rock centre, and was released and accumulated at the tops of oil reservoirs. The best area for prospecting for gas is between 500 m to 2000 m.
Extrapolating fracture orientations from horizontal wells using stress trajectory models
Authors: Rawnsley K. , Auzias V. , Petit J. P. , Rives T.
Published: November 2010

This paper presents a recently developed approach for extrapolating fracture orientations from horizontal wells. It is commonly accepted that tension fractures propagate perpendicular to the minimum principal stress. The hypothesis has been tested that in some cases, by modelling the stress trajectories within a faulted compartment, it is possible to reproduce the orientations of the tension fractures. The stress trajectory models we present are based on photo-elastic techniques. The models are first calibrated against outcrop fracture patterns and are subsequently applied to a reservoir database consisting of a 3D seismic block and a horizontal well with almost complete FMS image coverage. The results show that tension fractures may show perturbed orientations in the vicinity of faults. It is shown that by appropriate characterization of the seismic and well fracture data, it may be possible to use stress trajectory models to predict fracture orientation in a reservoir.
Qarn Alam; the design of a steam-injection pilot project for a fractured reservoir
Authors: Hartemink M. , Escovedo B. M. , Hoppe J. E. , Macaulay R.
Published: November 2010

In July 1996 a steam-injection pilot project was initiated in the Qarn Alam field in Oman. The objective is to test the steam-enhanced gas-oil gravity drainage of the heavy oil remaining in the matrix of the fractured carbonate Shuaiba reservoir. This paper presents the results of reservoir simulations that were conducted to investigate design and future interpretation of the steam pilot. Different simulation techniques were applied to describe the complexity of thermal processes and multiphase flow in a densely fractured reservoir. Pilot performance and areal advance of the steam zone were investigated. The possibility of oil rim lowering, prior to injecting steam, and of injecting steam in two different local crests, were also investigated but rejected on the basis of simulation results. Finally, locations for steam injection wells and pilot observation wells are proposed and requirements for pilot monitoring deduced.
Anatomy of growth fault zones in poorly lithified sandstones and shales; implications for reservoir studies and seismic interpretation; Part 2, Seismic reflection geometries
Authors: Morley C. K. , Burhannudinnur M.
Published: November 2010

Interpretation of seismic reflection data across growth faults reveals that many of the small-scale fault geometries recognized in outcrop can also be interpreted on seismic data. While some fault zones can be interpreted as a single fault plane other faults are made up of bundles of overlapping fault planes connected by various hard and soft linkage geometries. These fault zones can be up to 1 km wide. While the zones of deformation bands identified in outcrop cannot be detected on seismic data, the existence of similar fault zone geometries in outcrop and seismic data suggests that the deformation band zonation might also be similar.
Stratigraphy and petroleum prospects of Upper Jurassic carbonates in Iraq
Authors: Sadooni Fadhil N.
Published: November 2010

Following post-Toarcian rifting in Iraq, basin margin oolitic-peloidal shoals which pass into scattered, low relief sponge-algal buildups were deposited. These sediments form the Najmah Formation. In the basin centre, a condensed section of black shales were laid down (Naokelekan Formation). Later progradation accompanied by slow regression created a bull's-eye evaporitic basin in which the Gotnia evaporitic sediments were precipitated as a lowstand gypsum wedge and basin fill halite. Activation of basement faults during the Late Jurassic may be responsible for the widespread erosion and associated diagenetic features that are exhibited by the Najmah sediments which may suggest post-depositional exposure. The Najmah Formation produced 330 barrels of oil from the Samawa-1 well with oil shows in other wells that make it a potential reservoir. The main reservoir facies are oolitic-peloidal and dolomitic limestones.
Determination of porosity and permeability in reservoir intervals by artificial neural network modelling, offshore Eastern Canada
Authors: Huang Zehui , Williamson Mark A.
Published: November 2010

A quantitative integration of porosity/permeability measurements and well log data from the major reservoir intervals throughout the basin is carried out using a back-propagation artificial neural network (BP-ANN), modified with the Marquardt algorithm. After data preprocessing and training/supervising example preparation, a model for the relationship among porosity, permeability and well log responses was established with the BP-ANN technique. The BP-ANN model was then used to construct profiles of porosity and permeability in both cored and uncored wells for the Avalon, Hibernia and Jeanne d'Arc formations from well logs. The BP-ANN derived porosity and permeability curves provide a basis for further reservoir studies, such as inter-well permeable units recognition and correlation, and basin-wide reservoir quality evaluation.
Overpressuring in the molasse deposits of the Adriatic Basin in Albania
Authors: Gjoka Michail , Dulaj Alekssander
Published: November 2010

The South Adriatic foreland basin in Albania contains up to 7 km of Neogene molasse strata affected by gentle NNW-trending monoclines and anticlines. Gas-prone terrigenous-derived organic matter occurs in low amounts (<0.4% TOC) throughout the Neogene sequence. Overpressures affect the strata up to Upper Miocene (Messinian) level, creating anomalous values of density and resistivity in mudstones and of porosity and sonic travel time. The overpressures are principally due to the high Neogene sedimentation rates. Further gas discoveries are expected, onshore and offshore, in both normally pressured and overpressured Neogene reservoirs.
The depositional significance of 3-D seismic attributes in the upper Cenozoic of the central North Sea
Authors: Gregersen U.
Published: November 2010

Upper Cenozoic sequences have been studied in detail on 3-D seismic data, attribute displays and well logs, in order to illustrate the use of attributes in stratigraphy. Lowstand and uppermost highstand deposits are associated with high values of reflection strength, interpreted from logs as reflecting silty-sandy strata. Increasing values of reflection strength through the Upper Cenozoic are related to increasing sand content. Amplitude maps characterize sedimentary facies of systems tracts. An integrated study of timeslices, reflection intensity and logs reveal buried channels and their sedimentary facies. Shallow channels may represent glacial meltwater run-off during the interglacial Cromerian, while the succeeding more deeply incised valleys may be formed by glacioeustatic sea-level falls during the Saale and Weischel glaciations. The studied shallow section with good resolution may contribute to the method of using attributes in genetic facies analysis of subtle stratigraphic hydrocarbon traps, in deeper sections.
Predicting hydrocarbon accumulations below deep Permian salt in the Pricaspian Basin; the use of shallow geochemical indicators
Authors: Anissimov L. , Moscowsky G.
Published: November 2010

The Pricaspian Basin in the southeast of the Russian Platform contains a sedimentary column up to 20 km thick comprising Palaeozoic subsalt formations, Permian salt and suprasalt Mesozoic and Cenozoic terrigenous formations. The huge oil and gas reserves of the Basin are concentrated in subsalt Upper Palaeozoic carbonate reservoirs. Geologists generally agree that the hydrocarbons in the numerous, generally small fields discovered in Mesozoic reservoirs migrated from deeper, subsalt strata. This suggests that traces of fluids at shallow stratigraphic levels may indicate the deep, subsalt sources of the hydrocarbons and associated components. Subsalt reservoirs at depths of more than 6000 m are targets for future exploration. The location of hydrocarbon pools in such reservoirs may be indicated by geochemical investigations of the salt and of the terrigenous rocks above the salt. The distribution of geochemical indicators in the post-salt section may aid the prediction of undiscovered hydrocarbon pools in deep Palaeozoic carbonate formations.
The Rotliegend of the NE German Basin; background and prospectivity
Authors: McCann Tommy
Published: November 2010

The NE German Basin contains approximately 2.5 km of Rotliegend sediments, subdivided into four formations. These were deposited following the cessation of the Late Carboniferous/Early Permian volcanic episode and a c. 20 Ma period of erosion and non-deposition. Initial deposition was confined to two areas, but with increasing thermal subsidence the basin extended to the south. Petrographic and geochemical analyses suggest that the sediments are derived largely from cratonic or recycled sources. Volcanic and sedimentary rock fragments predominate. The succession was deposited in a relatively stable tectonic environment with sediment input derived largely from the Lower and Upper Palaeozoic strata of the Variscan hinterland and the Late Carboniferous and Lower Permian volcanics. Hydrocarbon prospectivity is confined to two main areas, with traps being predominantly stratigraphic and subtle.
Correlation of fluid inclusions and reservoired oils to infer trap fill history in the South Viking Graben, North Sea
Authors: Isaksen G. H. , Pottori R. J. , Jenssen A. I.
Published: November 2010

Organic geochemical correlations between fluid inclusions and associated oils and oil-shows in Mesozoic reservoirs in the Sleipner area demonstrate generation from the same source rock organic facies (type II) for inclusions in wells 15/9-1 and 15/9-19. For well 15/9-9 the oil show is from a mixed type II/III source rock, whereas the fluid inclusion is from a type II source. All fluid inclusions are less thermally mature than the associated free oils and are thought to represent the earliest hydrocarbon yield from the source rocks. GC/MS/MS analyses of the fluid inclusions proved essential for resolving biomarker compounds and correlating them to reservoired fluids. Among the biomarkers, bisnorhopane contents in the fluid inclusions are consistently lower than in the associated reservoired oil. The expected dilution effect of bisnorhopane as progressively more hydrocarbons are generated from kerogen maturation is not observed. The difference in bisnorhopane amounts in fluid inclusions and oils is primarily due to varying relative hydrocarbon yields, through time, from different source rocks.
Upper Cenozoic channels and fans on 3D seismic data in the northern Norwegian North Sea
Authors: Gregersen Ulrik
Published: November 2010

Miocene-Pliocene deposits of the northern Norwegian North Sea, quadrant 35, have been analysed on three 3D seismic surveys, 2D seismic sections and well logs to interpret the detailed stratigraphy, morphology and facies of regionally defined depositional systems. The interpretations might serve as analogues for subtle stratigraphic hydrocarbon traps in older deposits. A major Miocene channel system, possibly submarine formed, has been mapped. Analyses of the reflection heterogeneity attribute suggest sandy channel-fills and crevasse splays. Time-slices show pronounced Miocene-Pliocene incision close to the Norwegian continental North Sea margin. In a basinward direction mounded fans of high reflection intensity are identified at the mouths of narrow, sinuous feeder channels in the earliest Pliocene depositional sequence. Facies changes through prograding, deltaic systems tracts of the succeeding Pliocene sequence are identified from the reflection intensity attribute and logs. The systems were generally forced westward by Scandinavian uplift, while higher-order glacio-eustatic sea-level changes punctuated the westward prograding systems and formed high-frequency sequences.
Geostatistical reservoir characterization constrained by 3D seismic data
Authors: Dubrule O. , Thibaut M. , Lamy P. , Haas A.
Published: November 2010

Geostatistical inversion is developed for constraining a 3D geostatistical realization of acoustic impedance using a 3D seismic block. The geostatistical realization is constructed using a sequential variogram-based approach in such a way that the convolutional response of the realization fits with the actual 3D seismic data. The method is illustrated with a 3D synthetic example. The initial acoustic impedance model is generated using an unconditional simulation of one million grid cells. Then, using five wells 'drilled' in this model and the synthetic seismic obtained by convolution, the geostatistical inversion method is applied to reconstruct the initial acoustic impedance model. The 3D synthetic seismic block is matched in a matter of half-an-hour CPU on a standard workstation. Analysis of the results shows that the input geostatistical model (variograms, means and standard deviations) controls the higher and lower frequencies that are not present in the seismic amplitudes. The use of a '3D earth modelling' tool allows efficient management of the '3D earth model' constructed by geostatistical inversion, and visualization of the various inputs and outputs.
The effect of grain size on thermal conductivity of quartz sands and silts
Authors: Midttomme Kirsti , Roaldset Elen
Published: November 2010

Synthetic samples of different grain size fractions of quartz were prepared and the thermal conductivities measured with a divided bar apparatus. The measurements were carried out on dried and water-saturated samples both perpendicular and parallel to the main stress direction during compaction of the samples. A clear correlation was observed between the porosity and the measured thermal conductivities. For water-saturated samples the thermal conductivity decreases more with increasing porosity than for ideal isotropic material as predicted by the geometric mean model. A clear positive correlation was also found between the thermal conductivity and the grain sizes of the samples. When the expected effect of porosity on the thermal conductivity was excluded, a linear correlation between the logarithm of the grain size and the measured thermal conductivities of the water-saturated samples was found. An anisotropy effect (a = k/k
1
) in thermal conductivity was observed for the samples, being most prominent for the coarsest ones. The measured anisotropy is assumed to be mainly due to the thermal anisotropic nature of the quartz crystal.
Integrated use of well data for structural control of seismic interpretation
Authors: Hesthammer Jonny
Published: November 2010

Dipmeter data, core data, stratigraphic isochore data and seismic data provide the geologist with several different tools to obtain information on the orientation of bedding. When these data are integrated into a single database, the seismic interpreter can significantly improve the structural control of seismic interpretation by using all of the available information. In addition, any inconsistencies in orientation measurements from one or more data types are easily recognized, and the cause of the mismatch can be further examined. Experiences from the Gullfaks Field, northern North Sea, show that inconsistencies related to core data include non-optimal slabbing of cores, poorly developed bedding and misinterpreting sedimentary features as structural dip. Estimates of the orientation of bedding from stratigraphic isochore/isopach thickness estimates are poorly understood, or if repeated or missing sections related to faulting are not recognized. Bedding orientations from dipmeter data may be erroneous if the quality of the data are poor and the data points show significant scatter. Local variations in bedding orientation may be at a scale that will not be reflected in the seismic interpretation. In addition, in areas of poor seismic quality, seismic noise may interfere with real reflections and cause erroneous interpretation.
Palaeostructure and palaeogeography from 3D seismic interpretation; examples from the Permian Basin in Poland
Authors: Gorski Maciej , Trela Malgorzata , Kunicka-Gorska Wieslawa
Published: November 2010

The Permian Basin is the main target of exploration in western Poland. Porous Rotliegendes sandstone and two Zechstein carbonate formations are the most important reservoirs. Every depositional system includes different lithofacies, and interrelations create patterns of trap/reservoir and sealing horizons. Combination traps, with both structural and facial elements involved in their closure, create a comparatively high risk for exploration. Palaeogeographic analysis based on 3D seismic data presents opportunities for improved interpretation leading to a significant reduction of risk in exploration and development drilling. There is no direct information in 3D seismic data, but they allow us to reproduce the palaeogeography and successive stages of structural redevelopment by means of flattened seismic sections and construction of the corresponding maps, i.e. pseudo-palaeogeographical maps.
Facies related geological model; a reliable method to describe complex reservoirs
Authors: Rovellini M. , Brega F. , Monico C.
Published: November 2010

The proposed methodology utilizes the concept of facies as the basis for reservoir characterization. Facies represent the elementary units of the reservoir. They are objectively determined through a log-based cluster analysis, and are fully characterized with petrophysical properties from cores. A stochastic model is used to distribute facies and related petrophysical parameters (porosity, permeability and irreducible water saturation) within the reservoir volume. Several equally probable reservoir realizations are generated from the same model and tested in a flow simulator. The realization providing the best history match is selected for production forecasts.
A reservoir model for the main Pliocene reservoirs of the Bahar Field in the Caspian Sea, Azerbaijan
Authors: Abdullaev T. I. , Falt L. M. , Akhundov A. , van Graas G. W. , Kvamme T. , Flolo L. H. , Mehmandarov K. , Narimanov A. A. , Olsen T. S. , Seljeskog G. , Skontorp O. , Sultanzade T. , Tank N. , Valieva E.
Published: November 2010

In this paper the results of a reservoir evaluation study of the Bahar Field, one of the most important oil and gas fields in the Azerbaijanian sector of the Caspian Sea are presented. The study has concentrated on the most important reservoir sections, Balakhany X and Pereriv Suite, encompassing (i) sedimentological and stratigraphic interpretation, (ii) petrophysical analysis, (iii) structural interpretation, (iv) assessment of hydrocarbon distribution, (v) geochemical characterization of the hydrocarbons, (vi) assessment of reservoir compartmentalization, (vii) establishment of static and dynamic reservoir models in digital format, as a basis for calculating in-place resources and assessing the potential for improved oil recovery. The study has provided new and detailed insight into the reservoir architecture and properties of the Bahar Field. In a broader context this detailed information and data analysis is believed to provide an improved basis for evaluating other tested and untested structures in this prolific hydrocarbon province.