Abstract: Numerical models and recent outcrop case studies of alluvial-to-coastal-plain strata suggest that autogenic avulsion can control the stacking density and architecture of channelized fluvial sandbodies. The application of these models to subsurface well data was tested by the analysis of upper coastal plain deposits of the late Bajocian Ness Formation in the Brent Field reservoir, UK North Sea. These coastal plain deposits accumulated during the progradation and retrogradation of the wave-dominated ‘Brent Delta’. Sedimentological facies analysis and palaeosol characterization in cores were used to interpret the styles of palaeochannel avulsion. These results were then compared with the dimensions and distributions of channelized fluvial sandbodies that had been quantified by spatial statistical tools (lacunarity, Besag’s L function) applied to interpretative correlation panels between closely spaced wells. The results indicate that the distributions of channelized sandbodies may plausibly have been generated by avulsions and that they influence sandbody connectivity and pressure depletion patterns. Intervals of upper coastal plain strata with relatively wide sandbodies that display some clustering in their stratigraphic architecture are associated with a high proportion of avulsions by incision and annexation in core samples. Such intervals display relatively good vertical pressure communication and relatively slow, uniform pressure depletion.

Abstract Recent sequence stratigraphic debate on the Brent system have focused on the interpreted nature of the progradational trajectory (horizontal, slightly upwards or downwards) of the shoreline (Rannoch/Etive Formations) through time, as this gives a direct measure of how late Aalenian-Bajocian relative sea level changed during regression. Early interpretations emphasized the unified shallowing-upward nature of the Rannoch-EtiveNess depositional system, and implicitly accepted a uniform shoreline progradation, i.e. a shoreline trajectory that was horizontal or slightly rising, implying a stable or slightly rising relative sea level. No irregularities of the trajectory were noted, and unusual shifts in facies, grain size etc. were normally related to autocyclic processes. More recent work has suggested that in some instances there is evidence for more irregular shoreline progradation at certain times, and for fall(s) in relative sea level and forced regression. This evidence comes from incised valleys and deep erosion/subaerial exposure surfaces from the landward (Etive-Ness boundary) and basinward (Rannoch-Etive) reaches of the Brent system respectively. However, it is currently unclear if any of these downshift surfaces recognized in the strandplain/coastal plain and shoreface environments are in time-equivalent strata. Current debate is mostly handicapped by a lack of agreement on the origin and depositional facies of the Etive Formation. There is significant debate about the relative amounts of fluvial, tidal and wave influence detected in the strata of this formation, with some authors arguing for a dominance of fluvial distributaries and mouth-bar deposits, whereas others propose either tidal-channel and inlet deposits or wave-dominated shoreface and strandplain settings. The stratigraphy is impacted by this disagreement. The character and sharp base of the Etive Formation can be argued to be consistent with normal shoreline processes, where wave or tidal conditions can produce significant erosion in the shoreface, without the necessity of any forced regression. Other interpretations, particularly where the Etive Formation is seen in terms of fluvial facies and processes, require a significant basinward shift of the shoreline to explain the Rannoch-Etive superposition, and a fall of sea level to cause the erosive boundary between the two formations. However, there is now ample evidence, including new evidence presented here, that both of the end-member scenarios for the progradation of the Brent system are incorrect. The notion that the overall progradation was entirely a product of normal regression, during stable and/or slightly rising relative sea level, is negated by local evidence of incised valleys, of subaerial exposure and plant growth in lower shoreface strata in the Rannoch Formation, and of repeated erosion surfaces with coarse-grained lags at the base of the Etive Formation. On the other hand, the idea of continuous sea level fall or of a single, late-stage fall, such that there was regional valley incision of the Etive into the Rannoch Formation and that the former is entirely younger than the latter, is negated by local evidence of gradual upward facies change between the formations, of stratigraphic interfingering between the formations, and of time lines passing through the Etive into the Rannoch Formation. It is perhaps not surprising that the system’s overall regressive trajectory varied in time from being forced to being normally regressive, and that further detailed local studies are required before regional generalisations can be made.

Abstract Cumulative oil production to the end of 2000 from the Don Field was 15.4 MMBBLS, which with an estimated STOIIP of 152 MMBBLS represents a recovery to date of 10%. Don has been producing for over ten years. The field lies 15 km N of the Thistle Field, at the western edge of the Viking Graben in the northern North Sea. The structure of the field is complex, and it comprises several segments, the two largest of which have been developed, Don NE and Don SW. The reservoir sequence is Middle Jurassic Brent Formation, but more deeply buried and of a more distal facies than is typical for other fields in the province. The Don Field is a sub-sea development tied-back to the Thistle platform, and Britoil (BP) is the operator. The field has been developed with five producers, three in NE and two in SW, with a supporting water injection well in each part of the field. All wells have been drill deviated from a seabed manifold located over Don NE.

Abstract The Dunbar, Ellon and Grant oil and gas fields (also known as the Alwyn South area) are located in the southeastern part of the East Shetland Basin, approximately 140 km E of the Shetland Islands. Most of the accumulations lie in Blocks 3/9, 3/14 and 3/15, which are parts of Licence P090 operated by Total Oil Marine plc (33.33%) with Elf Exploration UK PLC as sole partner (66.67%). Ellon was discovered in 1972, Dunbar in 1973 and Grant in 1977. Dunbar consists of a number of generally N-S trending, westerly dipping Mesozoic fault blocks with variable amounts of crestal erosion. Reservoir is provided by fluvial, deltaic and shallow marine sandstones of the Middle Jurassic Brent Group, Lower Jurassic Statfjord Formation and Upper Triassic Upper Lunde Formation. The Brent oil composition of Dunbar varies with depth and evolves from volatile oil at the base of the column to gas condensate at the top without a discontinuity of composition. In addition there is a small gas accumulation within a Paleocene submarine fan reservoir in a compactional structure. Ellon consists of two westerly dipping fault blocks with gas condensate contained within the Brent Group. Grant is one westerly dipping fault block with gas condensate in the Brent Group. In both the Ellon panels and also in Grant, thin waxy oil ‘rims’ are found below the gas. The depth of the shallowest structural crest within the Alwyn South complex is 3100m TVDSS, with the deepest proven hydrocarbon at around 3800m TVDSS. Sealing for the Alwyn South accumulations is provided by various combinations of Cretaceous, Upper Jurassic (Heather and Kimmeridge Clay Formations) and Lower Jurassic (Dunlin Group) mudstones. The source rock for the hydrocarbons is the Upper Jurassic Kimmeridge Clay Formation, which is mature and adjacent to the fields. These accumulations are being developed from a tender-assisted minimally manned fixed platform with a total of 28 well slots located over the Dunbar Field, in a water depth of 145 m. The Ellon and Grant Fields are produced as sub-sea satellites to Dunbar from a well-head cluster located between Ellon and Grant, in a water depth of 135 m. First oil and gas production from Dunbar and Ellon was in December 1994 and gas production commenced from Grant in July 1998. The time lag between discovery and development reflects the complex geology (structure, compartmentalization, reservoir thickness variations, diagenesis and differing hydrocarbon compositions) with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. Total oil and gas initially in place is in the order of 850 MMBBL and 2.62 TCF respectively, with the current estimate for ultimate recoverable reserves being 200 MMBBL liquids and 1.28 TCF gas.