Deep-water Sandstones Research Articles

Deposition of Yanchang Formation deep-water sandstone under the control of tectonic events in the Ordos Basin

Abstract A large area of deep-water sandstone was formed under the combined action of delta and gravity flow in the central Ordos Basin during the depositional period of the Ch6 and Ch7 oil-bearing formations of the Yanchang Formation. According to U-Pb dating of zircons by the method of LA-ICP-MS, the ages of the tuff layers at the base and upper parts of the Ch7 oil-bearing formation are 228.2±6.0 Ma and 222.2±2.0 Ma, respectively. Based on the ages of the tuff layers, it is suggested that the gravity flow complexes at the middle-upper Ch7 and lower-middle Ch6 oil-bearing formations were formed 215 to 224 Ma. The timing of deposition of the tuff and gravity flow is roughly the same as the period when tectonics are most active in the Qinling area, i.e. middle Indosinian period. Therefore, the even, widespread tuff at the bottom of the Ch7 oil-bearing formation and the thick deep-water sandstone of the Ch6 oil-bearing formation deposited during an early lake regression period, are the direct outcomes of the tectonic event. Tuff layers are deposited under the influence of the middle Indosinian tectonic events, and the clastic composition of the top and base tuff layers vary greatly. The events control the formation of large-area deep-water depressions, change of depositional system, migration of the depo-center, and occurrence of gravity flows.

Seismic modeling in the analysis of deep-water sandstone termination styles

Innovative seismic forward modeling is used to illustrate the sensitivity within seismic data, and its application in the interpretation of onlap and pinch-out of terminating deep-water sandstones, two critical components in deep-water exploration and production. Sandstone quality, net-to-gross estimates, volume calculations, vertical connectivity, and stratigraphic trapping are all dependent on the sandstone extent and their seismic characteristics in these settings. However, seismic resolution is commonly insufficient to resolve the critical reservoir parameters. Seismic modeling of termination styles based on integrated outcrop and subsurface properties allows for depth- and resolution-focused predictive models to be built for improved subsurface analysis. This technique is currently underused as a method to better understand the sensitivity of seismic data to the target lithologies and their geometries. The Gres d'Annot Formation is a well-studied sand-prone deep-water system of Paleogene age, deposited in a bathymetrically complex setting. Six end-member termination styles are discussed, including three sand-prone styles—simple onlap (O s), draping onlap (O d), and bed thickening (O t)—and three heterolithic styles—advancing pinch-out (P a), convergent pinch-out (P c), and convergent thickening and pinch-out (P ct). Local thickening close to the system margins is common in both sand-prone and heterolithic terminating strata and plays an important function in the appropriate distribution of sandstone. The outcrops are interpreted as potential (process) analogs for the complex sandstone distribution and termination patterns observed in plays like the Paleogene of the Gulf of Mexico and the Jurassic of the northern North Sea.

Paleocene deep-water depositional systems in the North Sea Basin

Interpretation of 3D seismic reflection data supported by well data provides insights into the geometry of early Paleogene depositional systems along the eastern margin of the North Viking Graben. These deposits, which consist mainly of sandstones interbedded with claystones and siltstones, are interpreted to document deposition at the edge of a large base-of-slope to proximal basin floor fan system which was sourced from the eastern basin margin. Individual sandstone bodies are up to 80 m thick and occur within four sandstone-prone packages (DU1–4), and well-to-seismic ties indicate that the thicker sandstones (>10 m) are represented by channelized or sheet-like, high-amplitude anomalies. Both well and seismic data suggest that the sandstones are of limited lateral extent (<1–5 km), implying they were deposited in a series of channels. Channelization and compensational stacking of sandstones may have been at least partly controlled by differential compaction across previously deposited sandbodies. The study reveals that deep-water depositional patterns are more complex than is apparent from previous, lithostratigraphically-driven correlations and from regional isochron mapping. In particular, this study has implications for the controls on the distribution and reservoir architecture of deep-water sandstones.

Provenance of the Upper Cretaceous–Eocene Deep-Water Sandstones in Sangdanlin, Southern Tibet: Constraints on the Timing of Initial India-Asia Collision

AbstractThe first arrival of sedimentary material from Asia onto the Indian continental margin provides a minimum constraint on the timing of initial India-Asia collision. A combination of petrology, detrital Cr-spinel geochemistry, and zircon U-Pb dating of the Upper Cretaceous to Eocene deep-water succession at the Sangdanlin section, southern Tibet, provides evidence for major provenance change within the strata. The Upper Cretaceous–Paleocene Denggang Formation quartzarenites contain zircons with dominant Proterozoic-Ordovician U-Pb ages, with an additional age peak of Early Cretaceous, which we interpret to be derived from the northern Indian margin. By contrast, the lithic sandstones of the Early to Middle Eocene Sangdanlin and Zheya formations are dominated by zircons younger than 200 Ma, showing one major peak at ∼80–125 Ma and two subdominant peaks at ∼54–70 and ∼180–196 Ma, comparable to those from the Gangdese magmatic arc. Cr-spinels in the Sangdanlin and Zheya formations are abundant and char...

An integrated 3D seismic, petrophysical and analogue core study of the Mid-Eocene Grid channel complex in the greater Nelson Field area, UK Central North Sea

This paper presents an integrated seismic, petrophysical and analogue core study of the Mid-Eocene Grid deep-water Sandstone Member from the Nelson Field area, Central North Sea. Two possible turbiditic units were identified in seismic data. Grid 1 shows channel-like features and a complex stratigraphy whilst Grid 2 consists of scattered bright amplitude events (shown to be slumped shales and chalky limestones by cuttings analysis). Lower Eocene Tay Sandstone Member core from the nearby Gannet Field provided an analogue for sedimentary facies. This enabled petrophysical and seismic observations of the Grid Sandstone Member to be tied to sedimentological facies. An integrated model shows five facies associations and a complex reservoir quality distribution. A comparison with outcrop and seismic examples of channelized turbidites indicates that the Grid system represents a medium-scale channel complex, exhibiting multi-storey, nested offset stacking. This work presents a new example that provides a link between laboratory experiments on topographic interaction of turbidite flows with seismic-scale observations and facies determination. The Grid system also adds to our knowledge of Palaeogene turbidite evolution from sheet-like to channellike forms and provides a useful analogue for improving hydrocarbon exploration and production efficiency in adjacent areas.

Heavy mineral sorting in downwards injected Palaeocene sandstone, Siri Canyon, Danish North Sea

Post-depositional remobilization and injection of sand are often seen in deep-water clastic systems and have been recently recognised as a significant modifier of deep-water sandstone geometry. Large scale injectite complexes have been interpreted from borehole data in the Palaeocene Siri Canyon near the Danish Central Graben of the North Sea hydrocarbon province. The emplacement of large scale injectite complexes has been commonly attributed to seismic activity and consequent sand liquefaction. However, due to very small differences in textural and compositional properties, and the lack of depositional structures in deep-water sandstones, the distinction between “in situ” and injected or remobilized sandstones is often ambiguous. Large scale heavy mineral sorting (in 10 m thick units) is observed in several reservoir units in the Siri Canyon and has been interpreted to represent the depositional sorting. In this study we describe an example of effective shear-zone sorting of heavy minerals in a thin downwards injected sandstone dyke which was encountered in one of the cores in the Cecilie Field, Siri Canyon. Differences in sorting pattern of heavy minerals are suggested as a tool for petrographic/geochemical distinction between “in situ” sandstones and their related injectites, especially where primary sedimentary structures are removed by fluidization or minor remobilization.

Chapter 10 Tectonostratigraphy of the greater Barents Sea: implications for petroleum systems

Abstract Palaeogeographic and tectono-stratigraphic considerations in the greater Barents Sea show that the distribution of reservoirs and hydrocarbon source rocks from the Late Palaeozoic to the Palaeogene can be related to three tectonic phases. Firstly, the Palaeozoic Caledonain Orogeny caused uplift to the west, followed by eastward sediment distribution across the shelf, towards carbonate platforms to the east. Secondly the Late Palaeozoic–Mesozoic Uralide Orogeny induced uplift to the east, causing widespread clastic deposition and reversal of the sediment distribution pattern. Thirdly, major Late Mesozoic–Cenozoic rifting and crustal breakup in the western Barents Sea led to the current basin configuration. Reservoir rocks comprise Late Palaeozoic carbonates and spiculites, Mesozoic terrestrial and marine sandstones and Palaeogene deep-water sandstones. Hydrocarbon source rocks range in age from Silurian to Early Cretaceous, and are grouped into three petroleum systems derived from Late Palaeozoic, Triassic and Late Jurassic source rocks. Multiple tectonic episodes caused formation of a variety of trap types, of which extensional fault blocks and gently folded domes have been the most prospective. Volumetric considerations of generated petroleum indicate that charging is not a limiting factor, except in the western margin.

THE NEW ADVANCES IN CLASTIC DEEP-WATER FAN

Hydrocarbon reservoirs found in deep-water sandstone facies have now aroused geologists' interest in studying details of clastic deep-water fans. The research of deep-water fan has made great progress in recent years. The aim of this paper is to review and sum up a series of new advances and ideas in this field in the recent years. In general,it involves the following key points:deep-water fans can not only be formed in lowstand system tracts,but also in highstand system tracts where sediment supply is great. In some cases,submarine fans cannot be found in lowstand system tracts. Deep-water fans are mostly built by turbidite deposits,but sometimes debris flows can also generate fans. Strata successions of deep-water fans are not simply characterized by either upward-thickening or upward-coarsening cycles. Some new models have been proposed based on these views. More factors such as eustasy,basin tectonics,sedimentation rate,and type of submarine fan are considered. The models are divided into gravel-rich,sand-rich,mixed sand-mud and mud-rich categories and each one includes three types in terms of sediment sources:point sourced,line sourced and multi-sourced. These models are more comprehensive and more accurately reflect characters of deep-water fans. They are also an effective tool to predict sandbody distribution in hydrocarbon exploration.

Comparison of different spectral decompositions for non-marine deep water sandstone reservoir prediction in the Xingma area

It is difficult to identify and predict non-marine deep water sandstone reservoir facies and thickness, using routine seismic analyses in the Xingma area of the western Liaohe sag, due to low dominant frequencies, low signal-to-noise ratios, rapid lateral changes and high frequencies of layered inter-bedding. Targeting this problem, four types of frequency spectral decomposition techniques were tested for reservoir prediction. Among these, the non-orthogonal Gabor-Morlet wavelet frequency decomposition method proved to be the best, was implemented directly in our frequency analysis[zht1] and proved to be adaptable to non-stationary signals as well. The method can overcome the limitations of regular spectral decomposition techniques and highlights local features of reservoir signals. The results are found to be in good agreement with well data. Using this method and a 3-D visualization technology, the distribution of non-marine deep water sandstone reservoirs can be precisely predicted.

Reconstructing large-scale remobilisation of deep-water deposits and its impact on sand-body architecture from cored wells: The Lower Cretaceous Britannia Sandstone Formation, UK North Sea

The Lower Cretaceous Britannia Sandstone Formation comprises deep-water sandstones deposited in the Witch Ground Graben, Outer Moray Firth, UK North Sea. The sandstones form a major gas condensate reservoir stratigraphically trapped against the Fladen Ground Spur. Although the first-order architecture is a simple northwards-thinning wedge, the lower part of the reservoir has a high degree of internal heterogeneity. The presence of thick debrites interleaved with or replacing sandstone units suggests that large-scale remobilisation has significantly impacted the sandstone distribution. This paper aims to reconstruct the style, geometry and history of the remobilisation over a 20 km 2, densely drilled area of the Britannia Field, focussing on the lower reservoir interval where remobilisation is thought to be prevalent. The study is based on documentation of approximately 2000 ft (610 m) of high quality core from 11 wells, together with wireline data from an additional 26 wells. Two main phases of remobilisation are recognised, each associated with excision surfaces removing up to 45 m of previously deposited stratigraphy. These surfaces are overlain by debrites that can be an order of magnitude thinner than the inferred excision depths, so that up to 40 m of differential topography was created as a consequence of the remobilisation. Subsequent sandstone intervals are shown to heal this differential topography, giving rise to a simple layer-like, large-scale architecture despite the complex internal remobilisation-induced heterogeneity. Remobilisation has thus affected the sand-body geometry both by removing previously deposited sand intervals and by controlling the thickness distribution of subsequent sandstones. Integration of the model with data from uncored wells shows that spatial variability may in some areas occur on distances smaller than current core-spacing (450 m), diminishing the geometric predictive value of the model in these areas. The fully mixed nature of the debrites is interpreted to indicate efficient transformation of the remobilised mass into a debris flow, controlling the highly evacuated morphology of the failure area. This link between morphology and process is used to characterise the Britannia remobilisation morphotype and place it into existing mass wasting classifications.

Source-to-sink systems on passive margins: theory and practice with an example from the Norwegian continental margin

Abstract Source-to-sink system analysis involves a complete, earth systems model approach from the ultimate onshore drainage point to the toe of related active deepwater sedimentary systems. Several methods and techniques have evolved in recent years, from experimental and numerical modelling through analysis of modern and recent systems, to analysis of ancient systems. A novel method has been developed, bridging between the previous approaches and dividing and analysing source-to-sink systems based on linked geomorphic segments along the source-to-sink profile. This approach builds on uniformitarian principles. The method is driven by the need to understand ancient, subsurface systems and still has high uncertainty but is an original, first-order approach to source-to-sink system analysis. In modern systems, entire onshore-to-offshore systems can be analysed with a higher degree of confidence than in ancient systems and semi-quantitative relationships can be established. Application in ancient systems is much more challenging but, in some cases, antecedent morphologies have been preserved onshore that can be matched with offshore known occurrences of, for instance, sandy submarine fan systems. Along the Norwegian North Sea and Norwegian Sea margins the Paleocene deep-marine reservoir of the giant Ormen Lange gas field is such an example. There, antecedent onshore drainage patterns which formed the feeder system to the offshore, deepwater fan system can be interpreted and aligned with onshore palaeogeomorphological evidence. Understanding the palaeogeomorphic development of basement regions such as the Fennoscandian shield is of high importance for understanding the offshore presence of deepwater sandstones.

Extending the Exmouth Plateau post-Callovian fairway: WA-390-P phase I exploration

Discovery of the Jansz-Io field in 2000 established the presence of the Jurassic W. Spectabilis fairway in the deep-water Exmouth Plateau, North Carnarvon Basin. In conjunction with the regionally prolific Triassic Mungaroo gas play, this assisted in exciting record bid levels during the 2006 Gazettal of offsetting acreage, with the award of WA-390-P to Hess for a work commitment of 3,135 km2 3D seismic data and 16 exploration wells. In the first phase of exploration the 3D acquisition was completed and four wells positioned using 2D data were drilled in 2007. Three of these, Glencoe–1, Briseis–1 and Nimblefoot–1, were discoveries in the post-Callovian interval, with Briseis–1 encountering additional gas pay in the Triassic Mungaroo Formation. The W. Spectabilis sandstones encountered in Glencoe–1 were analogous to those encountered in the Jansz–1 discovery well, 75 km to the northeast. These are interpreted to have been deposited in a shallow marine environment with accommodation space controlled primarily by the relict topography of the Triassic fault blocks. In contrast, Nimblefoot–1 and Briseis–1 both encountered gas pay in deep-water sandstones of Berriasian age. These are interpreted to be delta-front turbidites sourced from the Barrow delta to the south, analogous to the Scarborough gas field, but in fault-bounded traps in which fragments of the hanging wall systems have been preserved in the degraded footwalls of major faults. Both play types are characterised by classic seismic amplitude and AVO anomalies.

Provenance of deep-water reservoir sandstones from the Jubarte oil field, Campos Basin, Eastern Brazilian Margin

The provenance of the Maastrichtian deep-water reservoir sandstones from the Jubarte oil field (Campos Basin, eastern Brazil), was studied using an integrated approach that included quantitative petrography, conventional heavy mineral analysis, garnet mineral chemistry and zircon geochronology. The reservoirs are predominantly coarse, poorly-sorted sandstones with feldspathic composition derived from uplifted basement terrains. The fourth- and fifth-order depositional sequences analyzed show no major variations in composition or in provenance through time. However, variations in apatite:tourmaline presents potential to be used as a parameter for sandstone correlation within the field. The composition of heavy minerals indicates derivation from high temperature and low-to-medium pressure aluminous metapelitic rocks, from granites and subordinate mafic rocks, derived from the Cabo Frio Tectonic Domain and the Oriental terrain of Ribeira orogen, characterizing a supply route from SW to NE. The low ZTR index, as well as the absence of low-grade stable heavy minerals and of metasedimentary rock fragments, suggest that by the end of Cretaceous all supracrustal, low-grade terrains had already been totally eroded, and that plutonic, infracrustal rocks were exposed, similarly to the present situation. The integration of the compositional and textural aspects suggests a tectonically active source area, located relatively close to the basin. The active tectonic uplift of the basement terrains provided a large volume of coarse, poorly-sorted sediments carried directly from mountain streams and alluvial fans to deep water. The high frequency shifts in apatite:tourmaline values support a direct derivation of the deep-water sandstones from adjacent alluvial systems with short but differential exposure to weathering. The voluminous deposition of such coarse-grained and immature turbidites under the general transgressive conditions of the Maastrichtian indicates a tectonic, rather than eustatic control on their deposition, with important implications for the exploration of similar reservoirs in Campos Basin and in similar basins of eastern Brazilian margin.

Calcite cement in Permian deep-water sandstones, Delaware Basin, west Texas: Origin, distribution, and effect on reservoir properties

Calcite cement is the dominant control on reservoir quality in turbidite sandstones of the Upper Permian Bell Canyon Formation, Delaware Basin. These well-sorted, very fine-grained arkoses were deposited in a basin-floor setting by channel-levee systems terminating in broad lobes. Calcite cement distribution in the East Ford and Geraldine Ford fields was mapped using core, log, and thin-section data. Calcite is concentrated in tightly cemented zones that are mostly less than 1 ft (0.3 m) thick. Areas that have high percentages of calcite-cemented sandstone (20%) occur along the margins of the sandstone bodies, in overbank and lobe deposits, where sandstone pinches out into siltstone. Areas that have the lowest percentage of calcite-cemented sandstone (10%) occur where the sandstone is thickest, in the channel facies. Isotopic composition of the calcite (13C = 1.8 to 3.0 [relative to the Peedee belemnite, PDB], 18O = 4.6 to 6.3 [PDB]) is consistent with the source of calcium carbonate being from dissolution of detrital carbonate rock fragments and marine skeletal debris. Because internal sources of calcite were apparently insufficient to account for the cement volume, cement components are interpreted as having been transported into the sandstones from organic-rich basinal siltstones and limestones. Feldspars buffered acidic formation waters near where they entered the sandstone, resulting in calcite concentrated near the sandstone margins. The calcite formed near maximum burial depths of 4800 ft (1.5 km) and temperatures of 104F (40C) from marine pore waters with 18O of approximately 0 (relative to standard mean ocean water). Most of the calcite-cemented zones are interpreted as being concretions that extend no more than a few meters laterally. Production data and geophysical log correlations suggest that some cemented zones are laterally continuous at least 1000 ft (300 m) and cause vertical reservoir compartmentalization. Laterally extensive calcite layers may be associated with the base of turbidite deposits.

Development of Rheological Heterogeneity in Clay-Rich High-Density Turbidity Currents: Aptian Britannia Sandstone Member, U.K. Continental Shelf

Abstract Upper Aptian deep-water sandstones in the Witch Ground Graben of the North Sea have been extensively drilled and cored in the Britannia Field. The upper part of the Britannia Sandstone Member comprises a series of thick (~ 3.8 to 16.5 m) sandstone beds that thin and pinch out against a paleoslope formed by the Fladen Ground Spur to the north. Deposition was from unusually large-volume flows that carpeted the deep basin floor and base of the lateral slope with sand. The flows were able to heal significant seafloor topography produced during periods of local slope collapse. The recognition of widespread early remobilization is new and results in a revised event-bed correlation scheme and casts doubt on relationships between spatial patterns of grain-size distribution, facies distribution, and paleoflow used to underpin previous models of deposit emplacement. The beds are here interpreted as the deposits of large-volume, axially dispersing turbidity currents, probably some 70 km from source, and within 25 to 35 km of their run out limit to the south-southeast of the Britannia Field. Single event beds contain a wide range of sand-rich facies (deposited progressively from turbulent suspension), and clay-rich facies, previously termed slurry deposits (deposited in cycles of en masse deposition from dilute laminar flow alternating with phases of suspension fallout from turbulent flow). Along the northern fringe of the system clay-rich facies dominate, but pass southward over six or seven km into progressively cleaner sand-rich facies. This trend in facies distribution is at a high angle to the inferred SE-dispersing paleoflow and is thought to reflect lateral suppression of flow turbulence from flow axes to flow margins controlled by relative changes in flow depth. In addition, the vertical arrangement of facies within beds always shows sand-rich facies at bed bases, passing upward often via distinctive banded facies into clay-rich facies, indicating a temporal flow transformation from dominantly turbulent to dominantly laminar, with an intermediate phase of alternating laminar and turbulent flow. This temporal transition in inferred flow conditions is similar to the inferred on-axis to off-axis spatial transition in conditions. Thus single clay-rich sediment gravity flows can evolve in both time and space to develop different rheological zones, of turbulent, transitional, and laminar character. In addition, certain debritic, clay-rich facies are now interpreted to result from post-depositional remobilization from off the confining slope to the north, and must be differentiated from the primary suite of depositional facies.

Leaves in turbidite sands: The main source of oil and gas in the deep-water Kutei Basin, Indonesia

More than 6 tcf of gas and 200 million bbl of oil and condensate have been discovered in upper Miocene sandstones in the deep-water Kutei Basin, offshore East Kalimantan, Indonesia. Chemical analyses of oil, gas, and condensate indicate derivation from land-plant source material. Conventional cores and cuttings of deep-water strata show that the best source rocks are sandstones, not shales. Organic material in deep-water sandstones includes laminar coaly fragments, pieces of wood, resinite, and other coaly debris. Laminar coaly fragments are dominant, and their size, shape, and cuticle structure indicate that they were leaf fragments. Fossil leaf fragments occur in all deep-water sandstone packages from the upper slope to the basin floor. Fossil leaf fragments were apparently carried into deep water by turbidity currents during lowstands of sea level. Within turbidite sandstones, fossil leaf fragments are concentrated in layers with up to 50 wt.% total organic carbon (TOC). Kerogen that was separated from these layers has hydrogen index values of 200–500 mg hydrocarbon/g TOC. Kutei Basin deep-water shales contain mainly silt-size vitrinite grains with poor generative qualities. Microscale sealed vessel pyrolysis and kinetic and generation modeling indicate that land-plant kerogens occurring in quantities similar to the upper Miocene sandstones are capable of generating the gas and oil found in deep-water fields. Hence, leaf fragments in turbidite sandstones are interpreted as the main source for deep-water oil and gas. Liquids derived from leaves have caused production problems that include high pour points because of high wax contents and emulsions formed when fatty acids combined with water.

Lower Cretaceous deep-water sandstone plays in the UK Central Graben

Abstract Up to the present, exploration of the UK Lower Cretaceous deep-water sandstone play has been confined largely to the Moray Firth basins. The Lower Cretaceous of the Central Graben area has been modelled previously as predominantly shale-prone, and hence unattractive to exploration. There is a growing realization that this may not be the case. Since seismic imaging of Lower Cretaceous sandstones is known to be poor whether hydrocarbon-bearing or water-wet, a robust depositional model must be constructed from well and regional geological data in order to predict sandstone distribution and geometry, and hence to aid identification of potential hydrocarbon traps. Of the hundreds of wells drilled in the Central Graben area that targeted deeper Jurassic-Triassic reservoirs, virtually all have been located on the flanks of the graben, or on intra-graben highs. However, 71 of these wells have proved sandstones or traces of sandstone within the Lower Cretaceous, giving grounds for optimism that more substantial deep-water sandstone developments may be present within the graben depocentres. Twenty-six leads have been identified within these depocentres; most of these are located within stratigraphic traps in interpreted detached basin floor fans.

深海底堆積物研究の進展：低海水準期堆積モデルの再構築

A falling-stage deep-water succession is characterized by sandstone-dominated channel-and-overbank deposits and age-equivalent depositional-lobe deposits. In contrast, a lowstand deep-water succession is muddier and is characterized by a thickening-upward pattern of distal overbank deposits. The base of the falling-stage deposits is characterized by a distinct erosional surface compared with the base of the lowstand deposits, which is commonly represented by a gradational contact to the underlying falling-stage deposits.Deep-water channels commonly exhibit meandering patterns similar to fluvial channels, and the channel-fill deposits are encased in muddy overbank deposits. The distribution patterns and volumes of coarse-grained channel-fill deposits developed mainly during falling- and lowstand stages can be estimated from outcrop and seismic data on the basis of several empirical relationships among width, depth, and sinuosity of deep-water channels. Hyperpycnal flows have recently been interpreted to be one of the important mechanisms for developing thick to very thick-bedded, deep-water massive sandstones (DWMSs). DWMSs commonly exhibit sheet-like geometry and abruptly thin out and fine to the downslope direction. These abrupt changes in thickness and grain size of DWMSs are interpreted to be a result of deposition of a sufficient volume of sand particles from precursor hyperpycnal flows, which are subsequently transformed into buoyant plumes with finer-grained sediment particles associated with residual lower-density turbidity currents flowing to the further downslope direction. Modulation and transformation of turbidity currents into debris flows at a channel-to-lobe transition zone were recognized. The transformation of turbidity currents into debris flows is interpreted to have occurred in response to incorporation of many siltstone clasts and finer-grained sediment particles into the precursor turbidity currents from muddy substrates. The finding indicates that a laterally continuous sandstone body from middle-fan channel to depositional lobe deposits internally contains muddy baffles, which develop heterogeneity of fluid flows in reservoir sands and sandstones.

The importance of stratigraphic plays in the undiscovered resources of the UK Continental Shelf

Abstract This paper analyses the statistics of existing United Kingdom Continental Shelf (UKCS) fields and discoveries as a means of assessing which plays are likely to contain the greatest untapped potential for stratigraphic traps. Current Department of Trade and Industry (DTI) estimates put the maximum discovered ultimate recovery of the UK at 50 billion (× 10 9 ) barrels of oil equivalent (BBOE); estimated technically recoverable undiscovered resources are between 4.1 to 21.3 BBOE, based on a prospect mapping approach. As of end 2003, 82% of the oil and gas fields and discoveries on the UKCS have been found in structural traps; 12% have been found in combination structural/stratigraphic traps and only 6% in stratigraphic traps. The majority of stratigraphic traps and combination traps occur in association with syn-rift (Upper Jurassic) and post-rift deep-water plays. There has been relatively little direct exploration for stratigraphic traps until recently, and a number of the major discoveries in stratigraphic traps were found by chance. Few substantial untested structural traps remain in the UK North Sea except at considerable depth with associated risks. We estimate that perhaps 50% of the UKCS undiscovered resources are located in stratigraphic or combination traps, principally within syn- and post-rift deep-water sandstone plays.

Large-scale hydrocarbon-driven sand injection in the Paleogene of the North Sea

The detailed study of many diagenetic carbonates (concretions, cemented bioturbation burrows etc.) and dykes of a large-scale sandstone injection complex, which are preserved in a cored early Eocene section recovered from the South Viking Graben (North Sea), provides evidence for the dyke emplacement by gas-driven sand injection and coeval methane seepage. The morphology, chemistry of fluid inclusions, isotopic signature (δ13C as low as − 35‰) and petrographic characteristics of the diagenetic carbonates reveal gradual carbonate precipitation with a contribution of carbon derived from methane oxidation. Stratigraphic and cross-cutting relationships reveal that sand injection post-dates the formation of the diagenetic carbonates and, therefore, the beginning of hydrocarbon migration. Fluorescing fluid inclusions, carbonate cement isotopic signature (δ13C as low as − 27‰) and petrographic observations of the injected sandstones indicate the persistence of hydrocarbons (including methane) after the injection process. Gas chromatography of fluid inclusions confirms the presence of methane in both diagenetic carbonates and injected sandstones carbonate cements. We suggest that gas influx in the Eocene deep-water sandstones increased pore fluid pressures during early burial and decreased the grain framework stability, inducing liquefaction and sand injection. Gas involvement in sand injection has been widely invoked to explain the large-scale injection complexes recently recognised in the Paleogene of the North Sea but had previously never been proven. Large-scale injection structures and hydrocarbon seepage appear linked in several localities with obvious great economic significance.