ABSTRACT The Ten Boer Member (ROCLT; Upper Rotliegend, Southern Permian Basin) is a claystone-dominated succession with thin sandstone beds, deposited on the margin of a large saline lake. The sandstone beds were deposited by fluvial channels and associated unconfined sheet floods in the distal part of a fluvial system. A recent re-perforation test in a depleted Rotliegend well successfully produced 30 Mm 3 gas from a thin ROCLT sandstone bed at only 50K Euro re-perforation costs. This success triggered a detailed study to map the fluvial fairways and assess the lithofacies associations of the ROCLT. Based on log and core analysis the ROCLT succession is subdivided into five cycles, each characterised by a high-to-low-to-high gamma-ray succession and an associated mudstone–sandstone–mudstone sediment sequence. The cyclic succession is interpreted as a wet–dry–wet climatic change. Log correlation panels and gamma-ray-log-derived net sand maps show that the sandstone deposits are concentrated in SSW–NNE-oriented belts 15–30 km wide. The belts are fairways for fluvial transport from the Variscan Mountain Range in the south to the basin centre in the north. The shape of the fluvial fairways changes from elongate belts to lobe shapes across a narrow east–west-oriented transition zone. Net-to-gross drops drastically north of the transition, and the sandy lithofacies changes accordingly from stacked sandstone in the elongate belts to thin sheet sandstone embedded in claystone in the lobe-shaped part. Over time the fluvial fairways show a lateral shift, and the entire fluvial system gradually progrades northward. The net sand maps assist to further constrain the locus of isolated sheet-sandstone reservoir units, and thus aid in future reservoir architecture modeling.

Abstract The passive margin stage of development of the Gulf of Mexico basin contains thick sequences of Miocene and younger siliciclastic sediments deposited in a framework of active listric growth faults. At depth, complex structures occur, characterized by multiple listric faults detaching at multiple structural levels. Between laterally adjacent fault blocks, displacement is transferred from shallower to deeper structural levels along lateral ramps, relay ramps, and transfer faults. These features may serve as sediment fairways, delivering reservoir quality sands to deeper structural levels. Continued displacement along the same or younger listric normal faults contemporaneous with deposition can position depositional thicks on the crest of anticlinal highs by displacing these sediments across antilistric fault bends. Constructing 3D models and kinematically reverse modeling the hanging wall blocks on laterally adjacent, linked fault systems provides a framework for deposition of reservoir quality sand. Forward modeling serves as a predictive tool for trap location, trap geometry, and the depositional extent of reservoir sands. An understanding of the relative timing of structural development to the timing of fluid maturation and migration can reduce the economic risk of a prospect. This study utilizes observations of 3D seismic data sets to construct 3D conceptual models which are palinspastically restored to the time of deposition of reservoir sands. Observation of seismic data and resulting 3D models yields criteria useful for the recognition of focused deposition and subsequent deformation resulting in trap emplacement. Applying this model to the structures lying beneath and adjacent to the Corsair and Clemente-Tomas fault systems serves as a predictive tool for locating sands and traps that are poorly imaged on seismic data. This model also provides a mechanism for transporting reservoir quality sands into regions typically devoid of sands along the deeper portion of the Texas shelf.

Abstract The margin between Côte d’Ivoire and the Niger Delta is a region with a common structural history, this being reflected in similarities in the stratigraphic response and play fairways identified across the region. There has been significant exploration on the narrow shelf characterizing the margin, resulting in a series of modest oil and gas discoveries. It is shown in this paper that many of the aspects of the plays in the unexplored deep-water regions of the margin are considerably more favourable to the development of giant fields than those on the shelf. This play-fairway review is based on the integration of existing publications with focused studies of multiclient 3-D seismic data over a number of areas. Play fairways are classified by seismic sequence and trap type, with an analysis of each undertaken. The most attractive deep-water play types are: (1) anticlinal traps involving late syn-transform (Apto-Albian) and early post-transform (Late Cretaceous) reservoirs, (2) combination traps involving ponded turbidites on the shoreward flanks of these highs, and (3) stratigraphic traps associated with large Late Cretaceous submarine fan complexes. The anticlinal play is associated with the terminations of the St Paul and Romanche fracture zones, with the more recent structuring generally associated with the latter. 3-D imaging and amplitude mapping is critical to prospect delineation, particularly for the combination and stratigraphic plays. Active kitchens are evidenced involving Early and Late Cretaceous source rocks in the Côte d’Ivoire and western Ghana to Nigeria segments of the region, which are consequently upgraded. Considerable volumetric potential is indicated that promises to make the region one of significant new exploration activity in coming years.

Abstract Integrated structural and sequence stratigraphic analysis, such as that described in this Memoir (specifically Chapters 3 and 4 ), represents a powerful tool for analysing a petroleum system by identifying hydrocarbon plays and constraining the regional distribution of the key elements of a play. A play is a combination of reservoir, source and seal facies which, together with a trap, may lead to hydrocarbon accumulations at a specific stratigraphic level. The geographic area over which a play is thought to extend is known as the play fairway and is usually determined by the depositional and erosional limits of the reservoir. This need not always be the case, however; play fairways based on the regional extent of a hydrocarbon source rock system or particular structural style are equally valid. Play fairway analysis is essentially an assessment of exploration risk at a basin scale. In the past the petroleum industry has applied the concept of risk mainly at a prospect-specific level. On a larger scale, applying risk analysis to the play fairway level in frontier basins permits channelling of exploration effort into the most prospective parts of a basin. Furthermore, by combining the risks for individual plays within a basin, different basins can be ranked, allowing exploration to be focussed towards particular basins. In more mature areas, the technique can highlight new plays in under-explored parts of the basin or, equally, provide an indication that the basin has very little remaining prospectivity and that it may be time to

Abstract The Eocene age Brimmond Sand Fairway is situated along the north-eastern flank of the Paleocene Forties Field (UKCNS blocks 21/10 and 22/6). Located along the western margin of this Brimmond Fairway are well imaged remobilized sands that form the reservoir interval for the Maule and Tonto Fields and, along with deep-water channels, the Brimmond Field. These Eocene Brimmond sandstones are encased in the Horda Shale which provides the sealing lithology. The interpretation of these remobilized and injected sands is driven from geometries derived from 3D seismic and historic logging of thin sandstones in the Eocene interval. Conical shape features with sills and steep dykes are mapped, with seismic evidence of injection along active faults and fractures. The developments of the Brimmond, Maule and Tonto Fields has been successful due to impressive seismic imaging with inversion and Direct Hydrocarbon Indicator (DHI) volumes allowing the identification of hydrocarbon bearing remobilized sandstones, along with 4D data imaging un-swept areas.

Abstract The Fairway field, Anderson and Henderson Counties, Texas, is a major oil field in a reef and reef-associated facies of the Lower Cretaceous James Limestone Member of the Pearsall Formation. The present productive limits are controlled largely by structure. The location of the reef also was influenced by a contemporaneously growing structure, so the reservoir can be considered to have a combination structural-stratigraphic trap, both physically and genetically. The James Limestone Member consists of several limestone types, differentiated on the basis of texture and fossil content in cores. Maps of the distribution of these rock types during successive stages of reef growth show that the main core of the reef, dominated by frame-building organisms, was in the northwest part of the field. The frame-builders were a closely associated suite of corals, stromatoporoids, algae, and rudistids. By about the middle of the time of development of the James reef, the center of growth was at its maximum, and smaller satellite reefs appeared in the southeast and southwest. A facies dominated by large bivalves occupied much of the area between centers of growth of the main frame-builders. The south-central part of the field was an area of persistent accumulation of carbonate sands and gravels. Carbonate muds and muddy sands were the dominant facies elsewhere. Porosity and permeability are present in all of the limestone types but are higher on the average in the associated limestones than in the reef proper. The porosity is largely secondary, although it is in part the result of enlargement of primary pores.

Abstract Despite a number of targeted and serendipitous discoveries above deeper Jurassic targets in the 1970s and 1980s, the high-quality Albo-Aptian sand fairway of the Outer Moray Firth, informally known as the Kopervik fairway, still remained relatively unexplored until the late 1990s. Following the Hannay and Goldeneye discoveries in 1996, the renewed impetus in exploration drilling on the trend generated a series of commercial oil and gas discoveries. This most recent exploration phase proceeded with a high ratio of well success to failure, despite the significant technical challenges specific to the Kopervik reservoir sands. For the most part, the explorationist has to contend with a play fairway consisting of subtle trapping mechanisms. The recognition of these traps is hampered by the acoustically transparent nature of the sand, ambiguous seismic imaging and depth conversion issues. The subsequent development of this high permeability reservoir remains equally challenging. Many discoveries have low hydrocarbon column heights with an active aquifer and/or mixed phased fluids, which lead to well deliverability and fluid processing issues. In spite of the technical complications, these discoveries are now being swiftly developed by various operators along the trend. In this paper, we discuss how interest in the fairway was renewed only recently, review how the technical concept was developed in an attempt to reduce exploration risk, and how, following a number of early and surprising discoveries, the fairway was rapidly and effectively appraised. Finally, as an example, we review how the application of joint development concepts will lead to the commercialization of the fallow Cromarty Field and the neighbouring Atlantic discoveries.