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69th EAGE Conference and Exhibition - Workshop Package
- Conference date: 11 Jun 2007 - 14 Jun 2007
- Location: London, UK
- ISBN: 978-94-6282-105-7
- Published: 10 June 2007
41 - 60 of 76 results
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Near surface models derived from ground roll, guided waves and Scholte waves
By E. MuyzertNear surface models derived from ground roll guided waves and Scholte waves Everhard Muyzert (Schlumberger Cambridge Research) SUMMARY____________________________________________________________ In normal exploration practice we make strenuous efforts to remove the effect of ground roll and other sources of self noise from the recorded data. We do this in the field with arrays and in the computer with sometimes complex processing schemes. Most of this so called self noise is a representation of the source wave field's response to the Earth and hence it should be usable as signal to provide extra information about the Earth and in particular about the near
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Diffraction imaging for fracture detection
Authors S. Fomel, E. Landa and M. T. TanerDiffraction imaging for fracture detection Sergey Fomel (University of Texas at Austin) Evgeny Landa (OPERA) and M. Turhan Taner (Rock Solid Images) SUMMARY____________________________________________________________ EAGE 69 th Conference & Exhibition — London UK 11 - 14 June 2007 INTRODUCTION Naturally fractured reservoirs are an important target for the oil industry. Such reservoir development requests information about the fractures obtained from seismic data. Usually this information comes from the effective media theories that predict a general elastic behaviour of a solid containing many inhomogeneities whose sizes are small (Grechka and Kasprov 2006). It is assumed that because of a small size (much
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Curvelet applications in surface wave removal
Authors C. Yarham, G. Hennenfent and F. J. HerrmannCurvelet Applications in Surface Wave Removal Carson Yarham (Seismic Laboratory for Imaging and Modeling Department of Earth and Ocean Sciences The University of British Columbia) Gilles Hennenfent (Seismic Laboratory for Imaging and Modeling Department of Earth and Ocean Sciences The University of British Columbia) and Felix J. Herrmann (Seismic Laboratory for Imaging and Modeling Department of Earth and Ocean Sciences The University of British Columbia) SUMMARY____________________________________________________________ Ground roll removal of seismic signals can be a challenging prospect. Dealing with undersampleing causing aliased waves amplitudes orders of magnitude higher than reflector signals and low frequency loss of information due to band
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Efficient optical architectures for seismic reservoir monitoring
Authors A. V. Strudley and P. NashFibre-optic seismic sensor systems are gaining increased interest in the context of field-wide permanent seismic reservoir monitoring. This interest stems from the expectation of improved reliability and lower through life cost compared to electronic component systems. Meeting these expectations for high channel count (>10 000 channels) is critically dependent on the optical architecture employed since this dictates requirements on total fibre and optical component count. A particularly attractive optical architecture using Time and Dense Wavelength Division Multiplexing is described. Examples of the implementation of this architecture in a field test of a 4C seismic optical sensor array are presented. A system noise floor below -140dB g/rt Hz, maximum signal level of greater than 0.9g in the seismic band and sensor to sensor cross talk better than -70dB were achieved confirming the viability of this approach for optical seismic sensing.
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Passive seismic monitoring of microearthquakes in mines and hydrocarbon reservoirs
More LessNORSAR has developed and applied processing and interpretation software for microearthquakes in hydrocarbon reservoirs and mines. In this paper we will discuss the challenges and limitations of borehole installations compared to subsurface installations in mines with respect to data analyses and interpretation. Since 2003 we have been working with microseismic data from the 1.4 km deep Pyhäsalmi ore mine (Oye et al., 2006). The data are recorded using an ISS International (Integrated Seismic System) network consisting of 12 vertical and 6 three-component geophones deployed at depths between 1 and 1.4 km around the active part of the mine. The Pyhäsalmi mine and ISS have kindly made the raw seismic data available to us, which we are processing independently with in-house software (Oye and Roth, 2003). In hydrocarbon reservoirs, the most commonly applied geometry is an array of geophones that is lowered into a single borehole. We have primarily been working with data from an 18-day monitoring of the Ekofisk field in the North Sea and with various data from the San Andreas Fault Observatory at Depth (SAFOD) based on different receiver array configurations within Pilot Hole and Main Hole installation (Oye et al., 2004). In principal, event localization can be based on phase arrival times and polarization information, the latter being essential for single borehole installations only. However, the polarization is strongly affected by local heterogeneities, especially at the receiver site, and the reliability of polarization determination depends to a high degree on the geophone quality and on proper installation/orientation. Uncertainties of 10-20 deg are typical. An automatic estimation of basic source parameters such as e.g. seismic moment, seismically radiated energy and corner frequency, can generally be determined under the assumption of a theoretical source model (e.g., Oye et al., 2006). The signal spectra are corrected for propagation path effects such as geometrical spreading and attenuation and source spectra are fit to the corrected signal spectra. Amplitude effects from the source radiation pattern can only be compensated for if the fault plane solution is assumed known or by averaging, provided that the receivers have sufficient spatial coverage of the source. The spatial coverage of the source is even more indispensable to achieve reliable fault plane solutions, since the solution space is non-linear and ambiguous. The assignment of fault plane solutions already implies the assumption of a pure shear failure, which might not necessarily be the general case. To resolve for such non-shear or volumetric components in the source, a moment tensor inversion is required, which in turn relies on even better spatial coverage. Due to a generally superior 3D geophone configuration in mining environments compared to hydrocarbon reservoirs, the quantity and quality of results obtained from passive seismic monitoring are significantly higher. This becomes also evident when considering the amount of microseismic installations, which have been proven valuable, if not indispensable.
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Monitoring mining seismicity and hazard analysis, examples from Poland
By S. LasockiMany examples have shown that the activity accompanying underground mining works can be hazardous both to underground staff and mining installations, as well as to ground structures. Magnitude of the strongest seismic events in copper mines of Legnica-Glogow Copper District (LGCD) in Poland exceeds 4.0. Furthermore, due to shallow focal depth, events of this size can give rise to peak ground acceleration of more than 2 m/s2. An accurate assessment of seismic hazard posed by mining-induced events is thus a problem of primary importance. Monitoring mining seismicity in LGCD is carried on both underground as well as from the surface. The underground seismic network is supposed to provide information about seismic sources. Yearly several thousands events are recorded and parameterized. The surface accelerometric ground motion monitoring aims at assessing seismic impacts to buildings and other man-made structures in this considerably urbanized area. The mining seismic events are weak earthquakes but the seismicity in mines significantly differs from the earthquake process. Firstly, mining event occurrence is predominantly controlled by time-varying mining works, therefore the active zones in mines are, by their nature, transient. Moreover, even during their lifetime, the activity of these zones changes considerably. In our approach to seismic hazard assessment in mines, locations and times of activity of the zones that will be active in the future are deduced from programs of mining operations. Characteristics of fracturing process in these zones are inferred from characteristics of the zones that were active in the past and can be considered as models for the future activity. The model zones are selected by expert judgment based on anticipated similarity between mining and geologic conditions of the past and future zones. The epistemic uncertainty of such selections is considered within the logic tree scheme. Secondly, due to the heterogeneity of the rockmass fracturing process, the magnitude distribution of seismic events induced by exploitation is often non-Gutenberg-Richter's, complex and multimodal. As a remedy the model-free approach with the non-parametric kernel estimator of magnitude density is applied. This approach ensures reliable estimates of probability functions of event size regardless the actual complexity of the underlying distribution of magnitude. The mentioned ways of analyzing the seismic hazard posed by mining-induced seismicity are illustrated by a practical example in which we predict future seismic activity and estimate limiting values for ground motion in the 20 years horizon.
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Multidisciplinary monitoring at the Izaute gas storage geophysical laboratory
By F. AubertinIzaute is a gas storage facility operated by Total and located in the South West of France. The reservoir, at a depth of 500 m, is filled in the spring and extraction begins in the fall. This cycle is repeated on an annual basis. This site has been selected to be a geophysical laboratory for monitoring techniques due to this periodic behaviour and its easy access. A wealth of geophysical data both seismic (surface and borehole) and non-seismic has been acquired at Izaute on a permanent basis. In this presentation the various geometries used are described. Conclusions are drawn on the on the usefulness of the various techniques in monitoring the movements of the gas - water contact. In particular, the acquired experience has helped promoting downhole optical seismic sensors within more integrated monitoring configurations.
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Permanent reservoir monitoring using passive microseismic techniques
More LessIn the course of the last ten years the author and his colleagues have been responsible for the design and installation of many permanent passive microseismic monitoring systems for oil, gas and CO2 sequestration projects. Theses systems are typically designed to be Life of Field installations with an operating life for the downhole components predicted to be > 15 - 20 years. In all cases the systems are intended to provide operators with relevant information about the response of the reservoir and the surrounding strata, the behavior of existing or induced structural failures, and the performance of the subsurface infrastructure, i.e. injection, casings, production tubulars, etc. The paper discusses the design parameters and results from four projects and illustrates how permanent passive microseismic monitoring systems can be used to assist operators in their quest to maximize extraction from a reservoir and to assess the effectiveness of production enhancement techniques.
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SeisMovieTM: a continuous land seismic monitoring system
By J. J. PostelTo overcome the difficulties linked to source and surface noises in the near surface on 4D land seismic acquisition, CGGVeritas has developed a seismic monitoring technology called SeisMovieTM based on low-energy surface or buried sources operating continuously and simultaneously in conjunction with a network of permanent receivers' antennae. The antennae can be vertical when very high sensitivity is needed or horizontal when spatial information is necessary. As the sources and receivers are stationary and cemented, one of the major causes of non-repeatability (positioning and coupling differences) is removed. Furthermore, it was found that, unlike their surface counterpart, buried sources and buried receivers could be almost insensitive to weather changes and provide a far better repeatability. This system is fully automated and remotely controlled. This type of high-resolution seismic monitoring has the potential to optimize exploitation scenarios: tiny changes in the seismic response (a few microseconds and a few percent) can be measured and calibrated to direct reservoir measurements. On top of that, the SeisMovieTM technology allows active and passive seismic to be combined for continuous reservoir monitoring. We will present the results of a one month continuous experiment on a SAGD pilot site in Canada showing a high level of repeatability in an industrial context. The steam plant adjacent to the recording area and nearby drilling operations during this period did not prevent the system from being able to detect significant 4D seismic signals.
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Time lapse reservoir monitoring: geophysical applications from the geothermal industry
Authors D. Watts, D. Colombo, S. Hallinan and G. Nordquist and S. RejekiHigh enthalpy geothermal fields exploited for electricity production are routinely monitored using geophysics, including both the long term reservoir evolution and short term injection and interference tests. We present examples of induced micro-seismicity data, gravity and repeat levelling (ground subsidence) programs from some of the worlds most significant fields, including The Geysers in the US and Darajat in Indonesia. The evolution of reservoir mass balance is monitored through repeated, high precision levelling and gravity surveys, enhanced by simultaneous monitoring of ground water level changes in shallow boreholes. The mass balance tracks the ability of natural fluid recharge to keep up with net loss from production and only partial, condensed fluid re-injection. Accurate MEQ locations, obtained through iterative 3D tomographic modelling of Vp and Vs velocities and subsequent location updating, track production and injection fluid paths. Fluid characteristics can be monitored through spatial and temporal changes in the Vp/Vs ratio, and moment tensor analysis gives and indication of changing fracture systems. The rates of fluid movement associated with commercial geothermal production are of the same order of magnitude as those expected from large oil fields, suggesting the monitoring techniques are transferable. The fluid dynamics are somewhat different, naturally, but analogies such as steam and water flood monitoring are directly comparable.
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Fluid induced microseismicity: from pore pressure diffusion to hydraulic
Authors S. A. Shapiro and C. DinskeExperiments with borehole fluid injections are typical for exploration and development of hydrocarbon or geothermal reservoirs. The fact that fluid injection causes seismicity has been well-established for several decades. Current on going research is aimed at quantifying and control of this process. The fluid induced seismicity covers a wide range of processes between two following asymptotic situations. In liquid-saturated rocks with low to moderate permeability the phenomenon of microseismicity triggering by borehole fluid injections is often related to the process of the Frenkel-Biot slow wave propagation. In the low-frequency range (hours or days of fluid injection duration) this process reduces to the pore pressure diffusion. Fluid induced seismicity typically shows then several diffusion indicating features, which are directly related to the rate of spatial grow, to the geometry of clouds of micro earthquake hypocentres and to their spatial density. In some cases spontaneously triggered natural seismicity, like earthquake swarms, also shows such diffusion-typical signatures. Another extreme is the hydraulic fracturing of rocks. Microseismicity occurring during hydraulic fracturing violates the Kaiser effect. Propagation of a hydraulic fracture is accompanied by the creation of a new fracture volume, fracturing fluid loss and infiltration into reservoir rocks as well as diffusion of the injection pressure into the pore space of surrounding rocks and inside the hydraulic fracture. Some of these processes can be seen from features of spatio-temporal distributions of the induced microseismicity. Especially, the initial stage of fracture volume opening as well as the back front of the induced seismicity starting to propagate after termination of the fluid injection can be well identified. We have observed these signatures in many data sets of hydraulic fracturing in tight gas reservoirs. Evaluation of spatio-temporal dynamics of induced microseismicity can contribute to estimate important physical characteristics of hydraulic fractures, e.g., penetration rate of the hydraulic fracture, its permeability as well as the permeability of the reservoir rock. Understanding and monitoring of fluid-induced seismicity by hydraulic fracturing in boreholes can help us to characterize hydrocarbon and geothermic reservoirs and estimates results of hydraulic fracturing.
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A real solution for reservoir monitoring in active wells
Authors S. A. Wilson and U. Rinck and E. CosteUntil now the use of permanent systems has required the drilling of additional monitor wells. In terms of instrumentation, permanent downhole seismic sensors represent the cornerstone for the implementation of full-field continuous passive seismic monitoring. The use of permanent downhole seismic sensors for use during 4D studies offers the prospect of accurate well ties, wavelet characterisation, and VSP on demand. A series of tool deployments within active wells has demonstrated that standard tool designs result in a noise level that is too high for viable microseismic monitoring. Common noise levels in such an environment vary from around 1 µ/s RMS to over 100 µ/s RMS depending on flow rate and completion design. Given that most recorded microseismic signal amplitudes are below 0.5 µ/s RMS, it is unsurprising that conventional downhole tools are unsuited for microseismic monitoring. The development of the PS3 (Permanent Seismic Sensing System) tool and the ?-lok mechanism solves this problem, providing a solution for the viable monitoring of microseismic activity from active wells. This is achieved by properly decoupling the sensor array from the flow noise in the tubing. Unlike conventional "decoupling" methods, the ?-lok completely detaches itself from the tubing. This feature results in a noise floor that is limited only by system noise and vibration in the formation itself. Although the combined value proposition for permanent passive seismic monitoring and 4D seismic remains undecided, the downhole instrumentation required to investigate this proposition is now real and present.
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Passive seismic monitoring for operations integrity at Cold Lake, Alberta
Authors C. M. Keith and R. J. Smith and J. R. BaileyPassive seismic monitoring has been ongoing at Imperial Oil's heavy oil operation in Cold Lake, Alberta since 1998. There are currently 81 dedicated monitoring wells with 5 or 8 tri axial geophones deployed in each well at depths ranging from 150 to 400 meters. The Cyclic Steam Stimulation process used to extract the bitumen, involves injecting large volumes of 300°C steam at greater than fracture pressure into the Clearwater bitumen-bearing formation at around 450m depth causing significant stresses and strains on the wellbores. The main objective of the monitoring is to detect casing failures and inadvertent fluid releases into the overlying Colorado shales caprock and the aquifers above them, thereby reducing the financial and environmental consequences. Daily interaction between the seismic analysts and field operations personnel, along with a systematic response plan ensures appropriate operational interventions are taken when passive seismic alarms occur. One challenge associated with operating a passive seismic system within a producing oilfield is managing the amount of noise generated by production operations. Data reduction is achieved with processes to reduce noise triggers, filter noise events that are triggered and compute channel specific statistics. Integration of the data acquisition sites, with a central data management server and through to Matlab-based analysis software, allows for seamless review of the daily statistics and daily analysis of the seismic events. Examples of the data types recorded and subsequent operational interventions are presented demonstrating a successful application of passive seismic technology.
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Sedimentary evolution of the Lower Clair Group, Devonian, west of Shetland: climate and sediment supply controls on fluvial, aeolian and lacustrine deposition.
Authors A. Witt and S. James and G. NicholsSandstone units in the Devonian Lower Clair Group vary from (a) thick, well sorted, medium sands deposited by aeolian processes, to (b) amalgamated fluvial channel deposits of coarser sand, to (c) thin sheets of fine sand deposited in floodplain or shallow lake settings. The six lithostratigraphic subdivisions (units I to VI) of the group are differentiated by changes in the predominance of fluvial, aeolian and lacustrine facies which are in turn controlled by sediment supply and climate. During periods of high sediment supply and relatively humid climate (Units II, IV and V), fluvial conditions dominated in the form of sandy to pebbly fluvial distributary systems on the alluvial plain. The sand body characteristics vary from stacked, coarse channel fills deposited by high energy braided rivers (Unit II) to decimetre sand sheets interpreted as the deposits of poorly channelised flow at the margins of the terminal fan (Unit V). At times of relative aridity, the fluvial system retreated and aeolian reworking resulted in extensive sheets of well-sorted sands deposited as dunes or more commonly on sand-flats (Unit III). Periods of wetter climate and reduced clastic input resulted in lacustrine facies fed by rivers which formed lake deltas which were coarse, fan deltas (Unit I) of fine-grained deltas (Unit VI). The Devonian Clair Basin is an example of deposition in a basin of internal drainage which was predominantly controlled by climatic and sediment supply variations: a predictive model for sand body character and distribution can be developed using an understanding of these controls on the depositional systems.
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Meet the Rotliegend Fractures
Authors J. Okkerman and M. de KeijzerThe Galleon and Clipper fields and the K07 and K11 fields are located in the Greater Sole Pit and the Broad Fourteens Basins (Southern Permian Basin), in the UK and NL southern North Sea, approximately 60- 100 miles E of Bacton. The Permian Rotliegend Leman B Sands and the Upper Slochteren Sandstone Member gas reservoirs were developed over a period of 35 years starting in the early 1970's. Short slabbed core sections showing the entire range of natural fracture types encountered in the cored intervals in the Rotliegend reservoirs that have been drilled are shown. The aim of the viewing is to go over the variety of fracture types encountered and explain how the presence/absence of these features affects well design and well productivity. We will close out with a discussion on what uncertainties remain in fracture prediction even after extensive study and integration of all available data
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Triassic Skagerrak reservoirs, Heron Cluster, Central North Sea
By T. McKieThe Heron Cluster fields form part of the Eastern Trough Area Project (ETAP), an integrated development with BP of a total of seven fields. The Heron Cluster comprises: Heron (discovered in 1988), Egret (1985) and Skua (1986). These form subsea tiebacks to a Central Processing Facility located over the Marnock Field. The main reservoir within the cluster is the Triassic Skagerrak Formation. The fields are classified as HPHT reservoirs, with initial pressures and temperatures of 9,300-12,900 psi and 300-350 F respectively. The Skagerrak Formation is a largely terrestrial succession deposited by terminal fluvial systems in a broadly semi-arid climatic regime. The section in the Heron Cluster area can be subdivided into an upper, more channel-dominated interval and a lower, poorer quality, more unconfined fluvial section, bounded below by the largely playa Marnock Shale and above by the lacustrine Heron Shale. These widespread shales may be time equivalent to the Rot Halite and middle Muschelkalk respectively, and record the expansion of playa, marsh and lacustrine environments marginal to these marine flooding (and evaporitic) events. The intervening coarsening-upward, splay to channel succession of the Skagerrak defines the large-scale progradation and expansion of terminal fluvial fans in response to increased hinterland run-off. Internally the Skagerrak reservoir is dominated by terminal splay deposits, arranged into cycles bounded by a hierarchy of shales which locally form laterally persistent, effective barriers to vertical flow and which locally compartmentalise the reservoir. The Skagerrak reservoirs in the Heron Cluster appear to have the following common characteristics: good lateral connectivity of channel belt facies in the upper section, but poor to zero vertical connectivity; large faults become 'leaky' with sufficient pressure drawdown, and there appears to be no aquifer support. The short term production behaviour of these reservoirs is not representative of their longer term behaviour, and in particular, short term well tests indicate a level of compartmentalisation which does not materialise during production.
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The Cormorant Formation (late Triassic) of the Tern Field, Northern North Sea
Authors S. Gould and J. MarshallThe Tern Field is located on the Tern-Eider Ridge at the western margin of the East Shetland Basin in the UK Northern North Sea, approximately 250 miles NE of Aberdeen. The late Triassic-aged Cormorant Formation oil reservoir was discovered by well 210/25-1 and the later (1977) Exploration well 210/25-3 recovered ~250ft of core from the Cormorant Formation in the northwest of the field. We have chosen to display the basal 120 ft of the cored interval, covering the main productive unit of the reservoir that lies at the top of the Lower Cormorant Formation and that is currently being developed. The base of the interval consists of a sequence of red siltstones and shales that display textures indicative of pedogenic modification. The sequence is sharply truncated by an amalgamated package of coarse-grained, poorly sorted sandstones. The sandstones contain abundant pebble-granule sized exotic clasts in addition to reworked, intraformational calcrete and clay material. Although lacking well-defined barform structures, some grading in grainsize may be observed. These sandstones form the main net-pay zone of the Tern Triassic reservoir; the sequence is approximately 30 ft thick and can be correlated across the field using formation pressure data acquired whilst drilling subsequent development wells. A sequence of variably mottled silts and shales containing calretised root traces and calcite nodules overlies the sandstone sequence, forming a seismically-definable marker horizon across the field. The sequence then evolves, with overlying micaceous sands being generally finer-grained, better sorted and characterised by abundant planar, low-angle planar and sub-ordinate climbing ripple lamination. Bioturbation fabrics and more elaborate root traces are also more abundant towards the top of the displayed interval. In the Tern Field, these sands are considered non-net, although in offset fields equivalent sands are on production. The Cormorant Formation in the Tern Field area is interpreted as being deposited within a continental fluvial distributary system. The displayed interval marks the transition point between two distinct continental fluvial styles. The lower interval was deposited in broad, low relief, coarse-grained fluvial distributary channels separated by sediment-starved and pedogenically modified floodplain intervals. The upper part of the interval heralds the onset of more unconfined, sheet-like fluvial deposition with colonisation of opportunistic fauna and evidence of more elaborate plant growth in the floodplain areas.
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The Brent Group (Middle Jurassic) of the Brent Field, Northern North Sea
By J. AlmondThe Brent Field is located within a N-S trending fault terrace, situated in the east Shetland Basin on the western margin of the North Viking Graben, UKNS. The Brent field was the first discovery (1971) in this part of the North Sea and hydrocarbons were encountered in the Middle Jurassic Brent Group and the Lower Jurassic/Triassic Statfjiord Formation. The Brent Group was cored in several of the early appraisal wells but the core on display comes from well 211/29 BC06 which was drilled as a down-dip water injector in 1980. The Brent Group comprise shallow marine, marginal marine and non-marine deposits of Middle Jurassic age (Aalenian - Bathonian). Five lithostratigraphic formations are recognised, Broom, Rannoch, Etive, Ness and Tarbert. These five formations are widely considered to record a major regressive-transgressive episode in which the Broom, Rannoch, Etive and Lower Ness Formations represent overall regression of a and the Upper Ness and Tarbert Formations record subsequent transgression of a wave dominated deltaic system. More recent studies of the regional Brent Group succession have recognised a variable number of high-frequency stratigraphic cycles within the major regressive-transgressive episode. These models interpret the Broom to represent a separate depositional episode to the overlying Rannoch-Etive-Lower Ness interval. The Upper Ness and Tarbert Formations are also interpreted to record multiple phases of transgression typically show tide- and wave-influenced features, with transgressive Tarbert shorelines trending along the increasingly active rift structures developing at that time. Selected intervals of core from the 5 lithostratigraphic formations in 211/29-BC06 are displayed in order to examine key sedimentological features, reservoir properties of the key Brent reservoirs and the stratigraphic relationships between some of the formations.
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Upper Jurassic shallow marine to paralic reservoirs, Curlew Field, Central North Sea
More LessThe Curlew Field is located on the western margin of the Central Graben and comprises a number of accumulations in a variety of Jurassic and Cretaceous reservoirs. The reservoir interval in the Curlew D Field is the Upper Jurassic Fulmar Formation, which is displayed here. Curlew is unusual in the Central Graben in that whilst regionally the upper Jurassic is largely represented by shoreface facies (Fulmar Formation sensu stricto) in this area the formation also comprises a succession of coastal plain and paralic facies informally assigned to the Curlew Member. Overall the upper Jurassic section seen in Curlew is a transgressive interval comprising coastal plain, tidal inlet, shoreface and shelfal facies. However, this succession is punctuated by a number of major flooding events, and candidate sequence boundaries can be identified also. Three discrete facies associations are displayed: The Lower Fulmar represents the lower part of the Curlew Member and is characterised by a heterogeneous assemblage of burrowed and stratified sandstones, siltstones, mudstones, coals and oyster beds. Towards the lower part of the succession rooted horizons and coals are more common. Overall this interval records variably brackish to fully marine, low energy conditions on a shallow, variably submerged fault terrace which ranged from salt marsh and tidal creek, to flood-tidal delta environments. The Middle Fulmar corresponds to the uppermost unit of the Curlew Member and comprises a series of stacked cross-stratified sandstone bodies interleaved with bioturbated intervals (mainly Ophiomorpha). Drifted woody material and carbonaceous drapes are present together with bivalve lags. Belemnite and ammonite fragments have been identified within the coarser grained lags. The base of this interval is a major erosional surface which may represent a sequence boundary. The fill comprises marine influenced channel-fills interpreted as tidal inlet deposits. The upper boundary of this unit is a regional transgressive surface. The Upper Fulmar, above the transgressive surface truncating the middle Fulmar tidal inlet facies, comprises intensely bioturbated, fine-grained lower shoreface facies arranged into a broadly transgressive succession which passes into offshore muds (Heather Formation).
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Faulting within Upper Jurassic claymore Mbr and piper Fm sandstones of the Witch Ground Graben, Outer Moray Firth, UKCS.
Authors R. Knipe, C. Souque, G. Phillips, A. Li and E. Edwards and G. JonesCores from the Upper Jurassic reservoirs of the Witch Ground Graben area display an array of fault rock types, primarily reflecting the clay content of the host facies. Clean reservoir sands contain deformation bands whilst more impure reservoir facies are typified by PFFR faults and smears within heterolithics and intra-reservoir shales. Fault zone examples show development at different burial depths, which impacts the degree of grain fracturing, cementation and stylolitisation of pre-existing faults and generates new faults with characteristics that differ from those formed prior to significant lithification. However, subtle variations in timing of faulting and access of hydrocarbons and diagenetic brines can lead to early shallow burial cataclasites and intra-reservoir fault zones clogged with heavy oils. In general, the fault zones present in core mirror the large-scale tectonic development of the area with the majority of structures being early, pre-lithification to shallow burial, extensional faulting and related to late Jurassic rifting. Modification of these faults during deep burial and later reactivation ties in with the more limited and focused Cretaceous-Tertiary activity in the area, when hydrocarbon migration occurred: this is seen as an interplay of fault activity, complex quartz-carbonate-exotic cementation and oil staining in fault zones within Upper Jurassic cores from the area. An important observation from the cored fault zones is that reactivation was often strike- or oblique-slip in nature and that in some instances breaching (dilatancy) occurred, whilst in others, such as late, cemented zones, re-sealing was achieved. The observations of key cored fault zones has been fundamental in developing a prospect risking and fault seal evaluation toolbox for the Witch Ground Graben, which may also be applied in other exploration and production areas.
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