ALBERT

Description: Structural geometries, faults and their movement histories, together with the petrophysical properties of flow units, are some of the major controls on hydrocarbon migration pathways within sedimentary basins. Currently, structural restoration, fault-seal analysis and hydrocarbon migration are treated as separate approaches to investigating basin geohistory and petroleum systems. Each of these separate modelling approaches in their own fields is advanced and sophisticated but they are not compatible with each other. Lack of integration produces incorrect palaeogeometries in basin models and inaccurate migration pathways. A combined structural restoration and fault-seal analysis technique, integrated with fast hydrocarbon migration pathway modelling code based on invasion percolation (IP) methods, is described. These modelling methods are used to develop a 4D basin modelling workflow in which evolving basin geohistories and geometries form an integral part of the analysis of hydrocarbon migration and trapping. By combining structural restoration and 3D fault-seal analysis it is possible to investigate the evolution of structurally complex traps through time. Integration of these techniques with a numerically fast migration pathway modelling technique allows hydrocarbon migration pathways and accumulations to be modelled through the evolution of the basin with time. Additionally, the effects of uncertainties in structural geometry, fault seal or any of the model input parameters can be explored using a risk-driven approach to modelling. These methods are demonstrated using synthetic, computer generated, 3D models and a well-constrained model of the Moab Fault, Utah, USA. Comparison of modelled structural geometries, fault-seal properties and predicted trapped hydrocarbons with outcrop data is used to validate the integrated modelling approach. The validated techniques are then applied to a seismically derived, 3D model from the southern North Sea, UK, to demonstrate how an integrated, risk-driven approach to modelling allows the effects of uncertainties in the distribution of hydrocarbon accumulations to be investigated.

Description: Authigenic kaolin is a major occluder of porosity at all depths in the Hutton-NW Hutton Brent Group reservoirs. Two polytypes, kaolinite and dickite, are present. Kaolinite occurs to a depth of ∼10,600 ft and is interpreted to be eogenetic. Dickite increases in abundance with burial depth, concomitant with increasing K-feldspar dissolution. Kaolin petrography indicates that kaolinite transforms to dickite via dissolution-reprecipitation at depths of ∼11,000 ft. Dickite has δ18O values characteristic of modified meteoric water for growth at temperatures of contemporaneous quartz authigenesis.Palaeohydrodynamic models involving meteoric water penetration down to 2 km through faults or Palaeozoic rocks of the East Shetland Platform are unlikely to provide the vigorous fluid throughput required for kaolin precipitation. Reverse post-rift modelling indicates that the crest of the Hutton-NW Hutton fault block was not sub-aerially exposed, precluding meteoric water ingress via this route. Eogenetic kaolinite formed in a meteoric water flush driven by topographic head on the Brent Delta. Dickite is, in part, derived from kaolinite dissolution, with additional sourcing from K-feldspar dissolution and Si-Al in pore-waters expelled from mudstones during burial. This model precludes the need for extensive fluid-flushing at intermediate burial depths.

Description: With increasing burial depth, intergranular porosity declines in a predictable manner according to theoretical and empirically established mathematical relationships. In basins with simple structural and thermal histories, average porosity can often be represented as an exponential function of depth. There are, however, common significant deviations from such a simple model of porosity evolution. Four mechanisms are recognized by which enhanced porosity may be generated or maintained during burial:development of overpressures due to restricted pore fluid escape;inhibition of mechanical compaction by selective cementation;inhibition of cementation as a result of hydrocarbon accumulation; orgeneration of secondary porosity due to either grain or cement dissolution together with simultaneous removal of reaction products.Secondary porosity may be generated either near the surface by the ingress of dilute meteoric-derived waters or at depth by the generation of ‘aggressive’ pore fluids. Deep burial diagnesis may encompass both closed and open system porosity generating reactions. In closed systems, increase in temperature concomitant with burial overcomes kinetic barriers enabling dissolution of metastable detrital minerals. By contrast, in more open systems, movement of fluids from either mudstones or evaporites to either overlying or adjacent sandstones introduces chemical disequilibrium that may cause mineral dissolution. Rapid, intermittent movement of fluids along active faults may additionally introduce temperature disequilibrium to further facilitate mineral dissolution in the proximity of faults. Over geological periods of time, however, faults are barriers to fluid flow and provide a mechanism for generating overpressure.In the Central and Northern North Sea basins, an upper diagenetic regime is separated from a lower diagenetic regime by a regional cover of Cretaceous mudstones and chalks. The Cretaceous sediments provide a regional seal which often coincides with the development of overpressure above deep graben centres reflecting restricted pore water escape. Fluid and solute movement between these two regimes is only possible where faults or gas chimneys penetrate the Cretaceous seal. In the upper regime, porosity loss in Tertiary sediments broadly conforms to the predicted decline of porosity with depth. In the lower regime, Jurassic sandstones on structural highs are characterized by extensive secondary porosity resulting from feldspar grain and carbonate cement dissolution, best preserved where oil accumulation rapidly follows porosity generation. Enhanced porosity can be expected either where sandstones interdigitate with mudstones or in graben centre plays adjacent to faults. This contrasts with graben margin plays where faults are the locus of pronounced cementation and complex diagenetic sequences are developed. In the absence of either oil accumulation or overpressure, secondary porosity either compacts or is occluded by a characteristic deep burial authigenic mineral assemblage. The present heat flow in the North Sea can be interpreted in terms of a residual thermobaric fluid flow from basin centres to basin margins which was probably initiated during the early Tertiary, coincident with the onset of rapid thermal relaxation subsidence.

Description: Of all the fossil fuels, natural gas is environmentally the cleanest, having a lower carbon content with respect to energy output than either coal or oil. Global demand for gas has risen steadily over the last decade and forecast demand growth now outstrips all other major energy sources. These two factors should dictate that gas will remain the energy source of choice until renewable alternative energy sources become readily and economically available.The UK is set to face a shortage of proven indigenous gas reserves. However, the known conventional global resources of natural gas are very significant, with reserves projected to last for 60 years at current production levels, and expected un-discovered resources predicted to exceed this figure. In addition, huge volumes of ‘unconventional’ gas resources are trapped in hydrates on the seafloor, in coal beds, in low-permeability sandstone reservoirs (so-called ‘tight gas sands’) or in shale deposits. Whilst the global resource base is good, the UK is set become a net importer of gas as the scope for significant new conventional resources is small, UK gas production is already very efficient, and opportunities for unconventional resources are limited.Traditionally, natural gas has been viewed as a stranded asset when located far from markets. However, since natural gas can now be efficiently converted to a liquid by cooling to −160°C, and then economically transported in ships, gas is now a mobile commodity like oil. The bottleneck of the European Interconnector, once seen as the key to UK gas supply, has thus been circumvented. Liquified Natural Gas (LNG) is being transformed from a small volume, exotic trade into a sophisticated global spot market, opening global gas exploration and production to deep waters and plays far removed from markets.Additionally, the steady advance of technology has played and will continue to play an active role in developing new gas exploration plays, optimizing recovery factors and rapidly monetizing reserves. Unconventional sources of gas will undoubtedly provide additional significant reserves, but on a timescale of ten years and beyond. The future of natural gas looks assured for some time to come.

Description: Proven global reserves of conventional natural gas are immense, with some 5500 × 1012SCF recognized world-wide, sufficient for around 60 years supply at current global gas production rates. However, total global growth in demand for gas is expected to average 3.2% over the coming decade and is projected to double by 2025. Along with accelerating liberalization of gas markets, this growth in demand will generate huge opportunities for gas explorers and producers. The exploration and reservoir engineering challenges are to find and produce three times more gas over the next 20 years than the industry has found in cumulative total since 1970. Current estimates suggest that 50% of conventional gas resources have been discovered to date. These resources are well characterized and exploration will have to extend deeper into sedimentary basins, in deeper waters, and in new plays, as well as creatively re-evaluate current acreage, to discover additional conventional natural gas. Tertiary deltas will be a major exploration play over the next decade.In the future, unconventional gas resources will be used increasingly to supplement high volume demand in developed markets and as a major longer-term source of energy. Natural gas in low permeability sandstone reservoirs, coal beds and fractured shale already accounts for more than 25% of natural gas production in the USA. Additionally, enormous volumes of natural gas are generated by methanogenic bacteria during early burial in marine sediments, much of which then contributes to frozen methane hydrates on the continental slopes. At present, much of this unconventional natural gas is categorized as hypothetical and requires fundamental scientific research before it can be considered as an economic resource.Historically, the commercial imperative has been to find gas close to markets. Shipping of liquefied gas, liquid gas derivatives and potentially solid methane hydrates (LNG, GTL and GTS technologies) around the globe, are changing the traditional patterns of gas exploration, transportation and market supply as new producers and demand centres emerge. LNG has already been transformed from a small volume, exotic trade into a sophisticated global market and GTL is likely to follow, opening global gas exploration and production to deep waters and plays far removed from markets.

Description: The Hutton and NW Hutton fields occur in highly faulted, rotated block structures in Block 211/27 of the East Shetland Basin, Northern North Sea. Fourteen wells that core Brent Group reservoir from these fields have been studied in order to characterize the relationship between clay mineral authigenesis and porosity modification in the sub-surface.Reservoir sands are present in the depth interval 9000–13 000 ft; the shallowest sandstones are subarkoses, contrasting with the deepest sandstones which are mostly feldspar-deficient quartz arenites. The change in composition is a result of diagenetic feldspar dissolution that takes place over the depth interval of study. Authigenic kaolin group minerals and illite are present over the depth range studied, and both exhibit depth-related increases. Three habits of authigenic kaolin group minerals are observed: ‘expanded-mica’, vermiform kaolinite and blocky dickite. The occurrence of vermiform kaolinite is enhanced in Hutton and the adjacent water zone, and does not occur in abundance below 10 500 ft. This habit formed as a result of syn-depositional meteoric water ingress. Structural models suggest that neither field underwent subsequent meteoric water flushing. At the deeper levels of its occurrence range, vermiform kaolinite shows signs of alteration to blocky dickite. Dickite occurs in both intergranular and grain dissolution pores. A depth-related trend of increasing dickite cementation is strongly linked to increasing K-feldspar dissolution. Enhanced dickite cementation is found adjacent to bed contacts in sandstones within mudstone sequences and in regressive sandbodies close to thick mudstone units. Illite shows a more pronounced depth-related increase across the studied interval. Illite precipitation is also genetically linked with detrital feldspar dissolution and is favoured by diminished pore water flow during deep burial. Authigenic clay distribution is partly controlled by local features such as detrital clay coats, in addition to larger-scale parameters such as primary lithology, facies associations, present burial depth and inferred palaeofluid flow. Intergranular porosity declines with increasing burial depth, while grain dissolution porosity increases with depth from Hutton to the shallow and intermediate depth wells of NW Hutton. Generation of enhanced porosity is not related to the unconformities overlying the Brent Group, but to sub-surface fluid migration pathways. Compaction is not significantly operative over the depth interval 10 000–13 000 ft. By 10 000 ft burial depth, up to 50% of the intergranular volume has been lost by mechanical compaction.