Davide Duranti

Origin and timing of sand injection, petroleum migration, and diagenesis in Tertiary reservoirs, south Viking Graben, North Sea

Petrographic, fluid-inclusion, and carbon and oxygen stable isotope studies of Tertiary injectite reservoirs in the south Viking Graben of the North Sea allow an understanding of the origin and timing of sand injection, petroleum migration, and diagenesis. Injection from shallowly (400 m; 1300 ft) buried Paleocene and Eocene unconsolidated sandstones occurred at the end of the Eocene, probably in response to earthquake activity. Liquid oil was already present in the parent sands prior to injection and leaked from the injectites to the seabed. Upward-migrating oil and basinal brines mixed with downward-invading mixed meteoric-marine pore fluids in the injectites, causing extensive biodegradation of the oil. Biodegradation of oil provided the driver for early carbonate cementation in injectites, causing diminished reservoir quality. However, early carbonate cementation also sealed off the injectites as potential escape routes for petroleum from the underlying parent sands. Oil (and gas) continued to migrate into the reservoir (parent) sands upon increased burial, causing a mixing of high-API oil with the early charged, extensively biodegraded low-API oil. The study of early diagenetic imprints reveals the evolution of injectite reservoirs, which forms the basis for understanding how to explore and develop them.

Sand injectites: an emerging global play in deep-water clastic environments

Although long-recognized features in the geological record, the hydrocarbon reserve potential of sand injectites has only recently become apparent. Advances in the quality and resolution of 3D seismic data allow the definition of a range of trap and reservoir geometries that have, in the past, not been deliberately targeted by exploration wells. Sand injectites form a new trapping style. They are intrusive, occuring as discrete traps and in combination with structural and stratigraphical features. Dykes, sills, emergent sills, scalloped tops and irregular bodies are identified as trapping styles. Reservoir quality is typically homogeneous and good, even when in an overall low net:gross system. The North Sea Palaeogene, in which at least 2.4 × 10 9 BOE reserves are associated with injectite fields, or fields modified by sand injection, is used as an example of sand injectite plays. Statistically, the additional reserve potential for sand injectites in the North Sea Palaeogene is high. Globally, the presence and significance of sand injectites is largely overlooked. As most sand injectite reservoirs of commercial significance develop during early burial and are associated with overpressure, play concepts are developed that combine mechanisms for overpressure development with sedimentology. Recognition of the presence of sand injectites will have a major affect on many deep-water and other plays both in terms of exploration and production.

Seismic Characteristics of Large-Scale Sandstone Intrusions in the Paleogene of the South Viking Graben, UK and Norwegian North Sea

Abstract Post-depositional remobilization and injection of sand can significantly change the geometry of deepwater clastic reservoirs. Features associated with these processes are particularly well developed in the lower Paleogene of the South Viking Graben of the UK and Norwegian North Sea. Seismic scale sandstone intrusions can be grouped in two classes. Class 1 comprises low-angle (20-40 degrees) tabular sandstone intrusions emanating from steep-sided in situ sand bodies within the Balder Formation. The intrusions may be 5-30+m thick and crosscut 120-250+m of compacted stratigraphic section. They terminate at an unconformity at the top of the Frigg interval where they may have extruded onto the palaeo-seafloor. Class 2 comprises conical sandstone intrusions that emanate some 50-300+m upward from distinct apexes located 400-700+m above the nearest depositional sand body. The conical intrusions may have been sourced from underlying sand bodies by clastic blow out pipes. Both types of intrusions seem to adopt their particular geometry independently of (but occasionally exploiting) polygonal faults within the encasing mudstones. Sandstone intrusions may be highly porous and permeable and are thus important both as reservoirs and as plumbing within thick mudstone sequences.

Fluidization structures produced by upward injection of sand through a sealing lithology

Abstract Subsurface and outcrop data are used to describe sand injectites, a group of genetically related features that includes sandstone dykes and sills, but also structures within depositional sand bodies. Fluidization is identified as the process by which sand is injected but we draw attention to the lack of constraints regarding fluidization velocity and fluid viscosity. Injectites are shown to develop between <10 m and 500 m below the seafloor. No relationship between depth of generation and injection geometry is found. Liquefaction of sand may produce sufficient excess pore fluid to create small sand injections during shallow burial. Large injectite bodies are identified on seismic data that may exceed 4 × 107 m3 are unlikely to be related to sand liquefaction. The general validity of hydraulic fracture as the mechanism for seal failure and propagation of injections is questioned. The association between the formation of polygonal faults and sand injection provides one of several alternative mechanisms for seal failure. Multi-phase intrusion is proposed as a likely mechanism for the formation of large sand intrusions, both because of the cyclical nature of most of the process invoked in their formation, and the author’s own observations. Many of the processes of sand injection remain poorly constrained.

Fluid escape from reservoirs: implications fromcold seeps, fractures and injected sands Part I. The fluid flow system

Abstract Fluid escape from reservoirs can take place through (hydraulic) fracturing, sand injection and seepage. Above several Tertiary hydrocarbon reservoirs in the North Sea, substantial amounts of fractures, sand injectites and seeps occur. Petrographic observations of these features show that all have carbonate cement associated with them that contains fluorescing hydrocarbon inclusions. The petroleum fluids escaping were partially trapped during the cementation and analysis of the cements allows understanding of the fluid flow system and the fluids involved. Cathodoluminescence indicates that sand injectites and fractures have one phase of cement associated with them. Seeps, however, show zoned carbonate cement, suggesting precipitation in a varying geochemical environment. This suggests that fractures and sand injectites were short-lived fluid-conduits, whereas seeps can act as fluid escape pathways over prolonged periods of time.

The structural and diagenetic evolution of injected sandstones: examples from the Kimmeridgian of NE Scotland

Injected sandstones occurring in the Kimmeridgian of NE Scotland along the bounding Great Glen and Helmsdale faults formed when basinal fluids moved upward along the fault zones, fluidizing Oxfordian sands encountered at shallow depth and injecting them into overlying Kimmeridgian strata. The orientation of dykes, in addition to coeval faults and fractures, was controlled by a stress state related to dextral strike-slip along the bounding fault zones. Diagenetic studies of cements allow the reconstruction of the fluid flow history. The origin of deformation bands in sandstone dykes and sills was related to the contraction of the host-rocks against dyke and sill walls following the initial stage of fluidized flow, and these deformation bands are the earliest diagenetic imprint. Early non-ferroan calcite precipitated in injection structures at temperatures between 70 and 100 °C, indicating that it precipitated from relatively hot basinal fluids that drove injection. Coeval calcite-filled fractures show similar temperatures, suggesting that relatively hot fluids were responsible for calcite precipitation in any permeable pathway created by dextral simple shear along the faults. During progressive burial, percolating sea water was responsible for completely cementing the still relatively porous injected sandstones with a second generation of ferroan calcite, which contains fluid inclusions with homogenization temperatures below 50 °C. During this phase, depositional host sandstones were also cemented.

Extrusive sandstones (extrudites): a new class of stratigraphic trap?

Abstract Extrusive sandstone bodies are identified as entirely stratigraphic traps associated with sand injectites. They may be difficult to recognize but have four-way dip closure and are invariably connected through underlying lower permeability strata to parent sandbodies by sandstone dykes or transgressive sills that belong to sand injectite complexes. Extrusive sandstones (extrudites) constitute an immature exploration target, which is largely untested by deliberate exploration wells. Using seismic data alone, the distinction between extrudites and intrusive sills, and between extrudites and depositional sands, may be problematic. Sedimentological criteria may make differentiation possible when core is available. Extrudites are likely to have been drilled and misinterpreted as conventional deep-water turbidites within deep-water systems affected by sand injection.

Sandstone intrusions: detection and significance for exploration and production

Early recognition of sandstone intrusions is a key factor in maximising exploration and production success of the Paleogene deepwater sandstone reservoirs of the northern North Sea. Discordant sandstone intrusions are readily detected in cores, image logs and high quality seismic data by cross-cutting relations with the encasing shales. Many examples of “ratty” sands seen in borehole logs and “artefacts” or “channel margins” seen in seismic data have later proven to be sandstone intrusions, with significant implications for exploration and production. The effects of sand remobilisation and injection include increased connectivity between reservoir compartments, thief sands caused by brecciation and injection into the seal, and large-scale modifications of reservoir geometry, in particular top reservoir. Detailed case studies from the North Sea Paleogene and pilot studies including various other deepwater clastic successions indicate that sandstone intrusions could prove to be an important factor in the development of some highly prolific deepwater provinces such as the West African Atlantic margin. Early recognition of sandstone intrusions in such areas is important for optimal development planning. It requires that the appropriate borehole and seismic data are acquired, and that sandstone intrusions are incorporated in the interpreter’s mindset.

Fluid escape from reservoirs: implications fromcold seeps, fractures and injected sands Part II. The fluids involved

Petroleum fluids escape from hydrocarbon reservoirs through permeable networks of fractures, injected sands and by seepage through low permeability host rocks. Carbon stable isotope analysis of carbonate cement associated with such structures shows that the escaping petroleum fluid is intimately involved in precipitating carbonate cement. Within fractures and injected sands, oxidation of chained hydrocarbons supplies bicarbonate to the co-existing aqueous solution from which carbonate precipitates (y 13 C around 20xV-PDB). y 13 C values within carbonate crusts associated with seeps are lower (as low as 50xV-PDB) suggesting a component of carbon derived from methane within these structures. This suggests a separation within the escaping petroleum fluids, with chained hydrocarbons remaining trapped within sand injectites and fractures, whereas more buoyant fluids (methane) continue to escape through low permeability host rocks. The abundance of fluorescing (chained) hydrocarbon inclusions within cement associated with fractures and injected sands versus the scarce occurrence of fluorescing inclusions within carbonate crusts associated with seeps is in agreement with results from stable isotope analysis. Oxygen stable isotope ratios indicate that carbonate cement within fractures and sand injectites precipitates at temperatures between 30 and 50 jC in the subsurface, whereas carbonate cement associated with seeps at the seafloor precipitates at temperatures around 0 jC. D 2003 Elsevier Science B.V. All rights reserved.