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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
51 - 76 of 76 results
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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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The lower cretaceous captain member turbidites of the Goldeneye Field
By R. DomínguezThe Goldeneye Field is located in the Outer Moray Firth of the Central North Sea and straddles across UK Blocks 14/29a, 14/28b, 20/3b and 20/4b, approximately 130 Km NE of Aberdeen. It is operated by Shell UK Ltd under an unit operating agreement between Shell UK Ltd, Esso Exploration & Production UK Ltd, Centrica Resources Ltd and Endeavour Energy UK Ltd, whose approval to present this material we acknowledge. The reservoir unit of the Goldeneye Field belongs to the Lower Cretaceous Captain Sandstone Member (also referred to as the Kopervik Sandstone), which is included within the Valhall Formation.The Captain Sandstones in the Goldeneye Field are split into two thick (up to 120 m) sand-rich units (A and D) separated by an extensive heterolithic shale-rich drape of the same order of thickness, Unit C. Unit E is a thin stratigraphic interval that lies on top. They fringe the southern flank of the Halibut Horst, a fault-bounded high, having been deposited by high density channelised turbidites. They were part of the Captain Fairway, oriented WNW-ESE and approximately 10-15 Km wide.
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Channel deposits of the Palaeocene Forties Fan, Nelson Field, Central North Sea
Authors J. Millington, E. Scott and A. MacLellan and C. GillThe Nelson Field, situated on the Forties-Montrose High in the UK Central North Sea, is a simple, low relief anticlinal structure with four-way dip closure. First discovered in 1988, the Nelson reservoir is found in the Palaeocene Forties Sandstone Member of the Sele Formation and comprises predominately of three main submarine channel systems that run in a NW-SE direction across the structure. Reservoir quality sandstones are found in the axis of the channels as well as in the channel margins and interchannel areas. Core intervals from three producer wells show the sedimentological characteristics of these three depositional environments. Core from 22/1-N9 shows an example of the deposits from a channel axis. The core is characterized by a high net to gross section (up to 95%) dominated by massive, structureless, amalgamated, predominately medium grained sandstone deposited from higher-energy flows. Muddy sediments are only preserved at the very top of a limited number of flows. A channel margin setting, as seen in core from 22/11-N16y, shows a lower net to gross range (50-60%). However, a large portion of the sands in the core, while thinner than the channel margin, posses very similar characteristics of the sandstones seen in the channel axis. The remaining sand in the cores preserves sedimentary structures (laminations, ripples, alternations of silts and sands) from deposition by lower-energy flows. Deposits in the area between the three major channel systems, as shown in the 22/11-N1 core, are dominated by muddy/silty sediments interspersed with sands. Again, even though the overall net to gross is in the range of 30-40%, the sands seen in the core are similar to the sand seen in both the channel axis and channel margin deposits. As the Nelson field is maturing, understanding the connectivity of the sands from the channel axis through the channel margin and into the interchannel areas is of paramount importance to determine what part of the reservoir has already been swept and where to find the remaining oil in the field.
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Heterogeneity and flow barriers in turbidites, Foinaven Field, UKCS.
By P. HugginsFoinaven is a Palaeocene, turbidite, oil field with subsidiary gas caps. The field comprises several reservoir intervals in an anticline, faulted into six fault panels. Located West of Shetland, off the north coast of Scotland, the field is a subsea development through an FPSO facility. Field development is a mix of depletion, with variable amounts of aquifer support and water injection support. This presentation discusses the interpretation of flow barriers in the main reservoir zone of Panel 0, an 80 m thick, stacked, partially amalgamated channel complex. Five producers are supported by three water injectors, and core data is available in two appraisal wells. Depositional setting for the sequence is of an overall prograding shelf/slope system with stacked, non-amalgamated, base of slope turbidite fans. Reservoir sands comprise channel complexes of various stacking and amalgamation architectures from more distal, distributary fan, lower units to more proximal, base of slope feeder channel, upper units. Individual channel elements, from facies and poroperm trends appear to be ca. 10-20m thick. The reservoirs are dominated by massive, amalgamated sands (no shales), with secondary heterolithic facies of non-amalgamated sands (ca. one metre sands with preserved turbidite shale caps, ca. 10cm), thin-bedded sands (poorer quality, cm-10's cm sand / shales) and shale conglomerates. Shale beds occur between and within the major sand units comprising 'background' hemi-pelagic deposition and slump/slide units. Reservoir quality is good, comprising fine to medium grained sandstones, with typical porosities of 23-30% and permeabilities of 500-2000mD. In Panel 0 pressure breaks observed in development wells (B08) can be related to heterolithic 'shale' package intervals identified in the well logs and correlated to facies in adjacent cored appraisal wells (19-3A). Correlation of pressure baffles and their relationship to key geological surfaces, i.e. channel erosive cuts, and facies associations, and thus to channel position and channel stacking architecture, help define the flow units of the reservoir. Note that only one well pair and one possible correlation is shown and discussed. The derived generic relationships are applied in guiding interpretation of the heterogeneity and flow unit / barrier architecture of the reservoir and population of the reservoir model. It can be seen from 204/19-3A that well log facies are not unique in terms of lithofacies. Interbedded sands and shales (Section 1) can have an identical log character to shale conglomerates (Section 3). Shale conglomerates, typically associated with channel bases, are unlikely to form pressure baffles. While channel bases with shale and slump drapes may form pressure breaks but have a higher risk of being discontinuous. Note that such surfaces may still form flow unit boundaries even if incomplete, as although they will not create a pressure compartment their low transmissibility may still control water sweep. Channel abandonment phases / off-axis marginal settings with non-amalgamated turbidites provide the greatest chance of extensive lateral preservation and thus forming pressure breaks and flow units. Where lithofacies can not be uniquely determined it is important to try and establish where a 'shale' package is in relation to the individual channel, i.e. channel cut or channel abandonment top, and its stacking arrangement.
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Looking for gas….in all the tight places
By M. DowneyWe have become accustomed to looking for gas in reservoirs that have good porosity and permeability, so that we may produce at high flow rates. What is the meaning, then, of the new search for "tight gas" reservoirs with low porosity and low permeability that is so captivating exploration? The reason for investor interest in "tight gas" is that these peculiar reservoirs do not need expensive search tools, have little dry hole risk, and have enormous lateral extent. "Tight gas" accumulations often occur over hundreds of square miles. These "tight gas" reservoirs appear to contain enormous quantities of gas that are challenging our engineering talents to extract profitably. These "tight gas" reservoirs are not merely poor quality conventional reservoirs, but have a number of unique characteristics that require new exploration and production techniques to be employed to efficiently find and develop the gas. These "tight gas" reservoirs require juxstaposition with a gas-expelling source rock, and to be discontinuous, at the reservoir level.
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Technology issues in development of tight gas resources
By T. SettariTight gas development is undergoing another cycle of "technology renewal". It is driven by the need to optimize mature plays and economically develop marginal gas (mostly onshore), as well as a new interest in tight gas internationally, often in new areas without history. The talk will examine some of the current technology issues, including: New look at the role of PTA and forecasting long term well productivity and reserves using some new well testing techniques, Changing philosophy of stimulation (away from conventional fluids to waterfracs and back to "hybrid fracs"), How microseismic monitoring is helping us to understand the reservoir behavior during fracturing and the role of geomechanics in tight gas stimulation, Shear fracturing - can we employ it to make better wells? New generation fracture modeling that integrates geomechanics (shear fracturing) and reservoir simulation.
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Tight gas sands: rock physics and seismic applications
By E. RojasToday, tight gas sandstone reservoirs are a vast resource. Due to their complexity and our poor understanding of these unconventional petroleum systems, new technologies are necessary to successfully exploit them. Some of the geological challenges present in tight gas sandstone reservoirs are: high reservoir heterogeneity, very low porosity and permeability, possible presence of natural fractures, uncertainty in gas/water contact and high possibility of overpressures. In this work, we have collected ultrasonic data on tight gas sandstone cores. We also analyzed cross-dipole sonic log data to understand the relations between elastic properties (e.g., Vp/Vs, P- and S-impedance) and petrophysical properties (e.g., porosity, lithology). We show the effects of pressure, lithology, and pore fluids on Vp/Vs. Finally, we quantify Vp/Vs variations due to changes in reservoir properties of tight gas sandstones with the potential to apply this information to interpret Vp/Vs extracted from AVO analysis or multicomponent reflection data. The results show that low Vp/Vs anomalies in tight gas sandstones can assist in prospect identification, because they are related to good quality rocks (sandstones with low clay content), presence of gas, and overpressure conditions.
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The Rulison project
By B. BensonRulison Field is a basin-centered gas accumulation with a long production history dating back to the 1960s. The reservoir is made up of fluvial deltaic sandstones and coals in the lower part of the Williams Fork Formation and alluvial plain sandstones in the upper part. Natural fractures significantly enhance the relative permeability to gas. Two multicomponent (9-C) seismic surveys were acquired in Rulison Field (Figure 1). Production is from Cretaceous Mesaverde tight gas sandstones (Figure 2). The pay section spans a 1200-foot thick interval that is overpressured. The reservoirs consist of multiple-stacked lenticular sandstone bodies with matrix permeabilities ranging from 5 to 80 microdarcies. Williams Production Company, operator, is conducting an infill drilling program to reduce well spacing to ten acres.
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Surface seismic multicomponent imaging of tight gas sands
Authors R. Harris and J. O‘BrienIn 2004, Anadarko Petroleum Corporation initiated a comprehensive geophysical program to evaluate how to best image over-pressured tight gas sands in the East Texas Basin, USA. These Upper Jurassic sands have a low acoustic impedance contrast with the encasing shales leading to a weak P-P reflectivity series. This program included the following elements: 3-D Seismic Imaging. A 72 square mile conventional 3-D seismic survey was recorded with single-component analog geophones. The seismic source consisted of buried explosive charges infilled as needed with vibroseis source points, Multicomponent Seismic Imaging. A 9 square mile three-component 3-D survey was recorded with a static spread of Vectorseis accelerometers centrally embedded within the larger conventional 3-D survey. All source points for the conventional P-wave survey were recorded concurrently by the Vectorseis spread, Multi-offset, multicomponent VSP survey. The objectives of the VSP program were (a) to provide direct observation and comparison of P-P versus P-S imaging of these tight gas sands, (b) to provide calibration of the P-P and P-S surface seismic data to well log data, and (c) to provide a means of registering the P-P and P-S data. The VSP program, presented in an accompanying poster display, provided strong encouragement for the use of 3-D surface multicomponent seismology to image these tight gas sands. The P-P 3-D survey was also quite successful, producing significantly improved imaging of the target interval compared to previous 2-D data. However P-S imaging of these deep targets (10,000' - 16,000') was disappointing, with poor signal/noise, limited bandwidth, and image quality inadequate for mapping purposes. In this paper we present the P-P and P-S 3-D seismic results, and discuss possible factors that may have influenced the multicomponent imaging results.
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Multicomponent VSP imaging of tight gas sands
Authors J. O‘Brien and R. HarrisLow porosity Bossier and Cotton Valley sands of the East Texas Basin, USA, have only a small acoustic impedance contrast with the encasing shales but a greater relative contrast in shearwave impedance. Thus multicomponent imaging may be more effective than P-wave imaging in exploring for these sand bodies.Vertical Seismic Profile data (VSP) acquired with both a near-offset and far-offset P-wave source clearly demonstrate the P-P reflectivity and P-S mode conversions within the Bossier section. While Bossier P-P reflectivity is low, it appears to be adequate for mapping thick sand bodies such as the York Sand, the main exploration target in this area. However P-P reflectivity is even lower for the overlying Cotton Valley Sands and is inadequate for imaging. In contrast, the far-offset VSP data demonstrate a high level of P-S mode conversion which is used to image this interval with high definition that is not provided by P-P reflectivity. This provides strong support for the use of P-S mode conversion imaging for seismic characterization of tight sand reservoirs. A P-P and P-S 3-D seismic survey was also acquired in conjunction with the VSP program. These data are shown in an accompanying poster. Near-offset shearwave VSP data acquired with a shearwave source show low signal/noise ratio and limited bandwidth for the downgoing waveform which we attribute to poor surface coupling or near-surface transmission effects. Such effects may also have a strong negative impact on multicomponent imaging of these sands using surface seismic techniques. We suggest that multicomponent 3-D imaging may provide a superior solution.
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Research on petrophysical characteristics and pre-stack inversion of tight gas reservoirs in Ordos Basin, China
Authors Q. Shouli, Z. Jinqiang and S. Jianquo and Z. XiaoyingDaniudi gas field in Ordos basin is of typical characteristics of tight gas reservoirs. The average porosity of gas reservoirs is less than ten percent. Through the petrophysical researches, we found that it is difficult to distinguish sand from shale by P wave impedance only. A set of petrophysical parameters was studied to find those that are sensitive to gas bearing sands. We concluded that Poisson ratio is an effective parameter to distinguish sand form shale in research area. AVO behavior of gas reservoirs were also studied in the paper. As the P wave impedance of sand very close to that of shale, AVO behavior of gas reservoir belongs to the second AVO class. By careful examination of field data, we found that it was difficult to watch such AVO behavior because of the low resolution of the data. Another difficulty occurred in inversion is the presentation of strong reflections caused by coal bed, and the reflection of reservoirs is overwhelmed by the strong reflections caused by coal bed. To overcome this problem, a model based pre-stack inversion technique was employed to get P wave impedance and S wave impedance simultaneously. Wavelets that were gotten form tie well to seismic data have high similarities. Log curves must be handled carefully to build a suitable initial model for inversion. The result shows that pre-stack inversion can provide a partial solution to the seismic prediction of tight gas reservoir in the research area.
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Well completion design for tight reservoirs: A 3D dynamic simulation approach
Authors S. Valzania and A. CiucaA new 3D black oil simulator, Quiklook by Halliburton, was tested in order to assess the effectiveness of hydraulic fracturing both in term of FOI (Fold of Increase) and RF (Recovery Factor). The actual way of modelling hydraulically fractured wells in 3D reservoir simulators is to approximate the fracture behaviour with a modified skin or productivity index. Neither methods can be considered realistic because of neglecting the modification of fluid flow into the reservoir and through the fracture itself. Quiklook, can easily generate accurate prediction of post-fracture performances thanks to an automatic grid generation of the reservoir and to the possibility of a local grid refinement (LGR) in the region of the wellbore and the fracture tip, as well as in the blocks adjacent to the fracture plane. A conceptual reservoir model with low permeability characteristics (1 mD horizontal, 0.1 mD vertical) was built using realistic parameters. In the first step of the work the fracture characteristics were optimized in terms of geometry and conductivity for a vertical well. In case of horizontal wells, efforts were made to deliver the optimal fractures number and spacing. The performance of the traditional unfracturated wells were compared with the fractured ones in term of Productivity Index and Recovery Factor both a medium term (5 years) and in a longer term view (10 years). Results of the study show that the optimal completion strategy has to be established on production and economical constraints and the horizontal well with multiple fractures shows better production performances compared with traditional horizontal well or vertical fracturated well.
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Integrated field management and completion processes for optimized tight gas reservoir development
By A. AlyAs gas demand rises and operators turn to tight gas reservoirs for new supplies, the need to optimize the capacity and recovery potential from this type of reservoir has risen. Thus, a process has been developed that enables the data and activities of multiple domains to be integrated for single-well completion optimization and field geocellular and simulation modeling. Through this process various development scenarios for completions and drilling locations can be systematically and rigorously analyzed. The field management process has resulted in significant improvements in production optimization, as well as single-well and field development planning.
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Demystifying tight gas reservoirs using multi-scale seismic data
Authors R. Bridges and M. RothLow permeability sand and shale reservoirs in the US Rocky Mountain region are estimated to hold nearly 7000 tcf of gas reserves (DOE 2003). In a typical reservoir, hundreds or thousands of feet of stacked fluvial sands are gas charged, with natural and induced fractures being essential for economic gas production. While seismic data is useful for identifying major geologic interfaces and faults, the thin and complex nature of these channel sands are typically below seismic resolution confouding interpretation at the reservoir level. Well planning optimization generally consists of progressive downspacing of wells, aided by a regional understanding of pressure gradients and fracture and stress orientations. Extensive seismic experimentation has been performed over the Rulison "tight-gas" field in west-central Colorado, USA, as part of the multi-year Reservoir Characterization Project. Over the past five years, three separate seismic surveys have been performed over this field, using 9-component seismic technology. This combined application of time lapse and multi-component seismic techniques has provided unique insights into fault and fracture orientations and reservoir pressure changes resulting from gas production. An additional seismic technique, passive microseismic monitoring, is supplying an additional reservoir perspective, confirming hydraulic fracture orientation estimates and quantifying the effectiveness of well stimulation efforts. In combination, the integrated application of multi-scale seismic, spanning time-lapse, multi-component and passive measurements, is leading to better understanding of key properties determining well production in a typical tight-gas reservoir.
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Use of frequency dependent anisotropy
By X-Y. LiConventional methods for seismic fracture detection are based on observation of seismic anisotropy. The anisotropy is assumed to be independent of frequency, and consequently we are able to produce maps of fracture orientation and intensity. Nevertheless, recent work has challenged the assumption of the frequency independence of anisotropy, and suggests that information on the orientation and dominant scale lengths of open fractures can in principle be inferred from observation of frequency dependent anisotropy. Here we present several examples on the use of frequency-dependent anisotropy in tight gas reservoirs. The first example is a walkaround VSP from an on-shore fractured gas reservoir in North America that allows us to demonstrate the existence of frequency dependent P-wave anisotropy and its links to preferred fluid flow direction. The second example is a multiazimuth walkaway VSP data from a fractured reservoir in the UK continental shelf where we believe that we are able to determine the orientations of the open fractures using P-wave attenuation anisotropy. The third example is a multicomponent VSP data from a tight gas reservoir in North America, in which fractured scale length is inferred from the frequency dependent shear-wave splitting. Our results suggests that the concept of frequency dependent anisotropy provides considerable scope for improving seismic fracture characterisation based on both P- and S- wave data by providing information on the scale lengths of the open fractures.
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Tight gas reservoir characterization from seismic attributes
Authors H. Shumin, C. Zhaoyou and D. Ning and L. ZhenfengWith the development of seismic technology, more and more seismic attributes come into being. More information than just time reflection is used to prospect hydrocarbon reservoirs. The study and interpretation of seismic attributes provided researchers with some details about geometry and physical parameters related to sedimentary facies, sands and fluids. In the prediction of tight gas reservoirs, seismic attributes analysis should be executed in a hierachical structure for staging objects (facies, sands, porosity and gas saturation) with different scales. A case study dealing with reservoir characterization is presented in this paper. 3D Seismic attributes have been used to map the reservoir facies and sand distribution in the area where identification of tight gas sands is a major challenge to development drilling. The whole process is divided into 3 steps - using waveform and coherence to delineate the sedimentary environment controlling the sands distribution, applying seismic amplitude analysis for sands predicting, combining acoustic impedance and corresponding logs to characterize porous and gassy sands. The above results ware validated by drilling a number of wells afterwards.
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Tight gas in the Neuquén Basin, Argentina
Authors A. Coppoli, B. Ghiggeri, E. Zardo, E. d`Huteau and P. Cabañas and V. Martínez CalThe high consume of gas in Argentina has demanded the increase of gas production and the developing of the tight gas resources. Here, we will describe the most characteristics tight gas reservoirs of the Neuquén Basin: the Mulichinco, Las Lajas and PreCuyano formations. Mulichinco`s, with permeability as low as 0.001 mD, is in early development stage and has several pilot wells planned for 2007 to better define its potential; Las Lajas`, focus of the Argentinean Tight Gas main project, produces only if hydraulic fractured, and needs new technologies to better define its sands thicknesses and trap system; Precuyano`s, with reservoirs of volcanic origin, presents a highly structural complexity and requires different fracture approach for each pay zone.
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