Petroleum Geoscience - Volume 5, Issue 4, 1999

A study of interval velocities from almost a thousand wells reveals basinwide differences in physical properties of the Cenozoic deposits of the North Sea Basin. These differences relate primarily to the sediments below the mid-Miocene unconformity as testified by a subdivision of a subset of these wells. Velocity-depth anomalies are mapped relative to a constrained, normal velocity-depth trend derived for marine Jurassic shale: tt = 465.e (super -z/2435) +180, where tt is transit time in mu s m (super -1) , and z is depth in metres below sea bed. The upper Cenozoic deposits are close to normal compaction, whereas anomalies for the lower Cenozoic sediments outline a zone of undercompaction in the Central North Sea that corresponds to the overpressure in the Upper Cretaceous-Danian Chalk. The overpressure results from a balance between the load of the upper Cenozoic deposits, and the draining determined by the thickness and sealing quality of the lower Cenozoic sediments. The shale trend may be more widely applicable to marine shale dominated by smectite/illite. This suggestion is based on the observed correspondence between velocity anomalies and pressure data, and due to the match between trends for marine shale of different ages in the North Sea and in the US Gulf Coast area over a significant velocity range.

Significant three-phase regions can occur in a range of reservoir development strategies and oil relative permeability may then critically affect ultimate oil recovery. Unfortunately, three-phase oil relative permeabilities are not generally well characterized. In this paper we focus on theoretical methods of estimating three-phase oil relative permeabilities, as typically applied in reservoir simulation. In the absence of good physical models, we propose applying a mathematical filter to the many existing methods before fitting to measured data. First, the key characteristics of methods for predicting three-phase oil relative permeabilities are discussed, including choice of variables, behaviour at low oil saturations and three-phase residual oil saturations. Second, a numerical comparison of both predicted oil relative permeabilities and predicted incremental oil recoveries for immiscible WAG over waterflood is presented. None of the four most commonly used formulations assessed passed the mathematical filter successfully. Shortcomings were found in both of Stone's commonly used formulations for estimating expected recoveries. A wide range of incremental oil recoveries for immiscible WAG was found from choosing different formulations or different three-phase residual oil saturations. Some recommendations for best practice have been made.

The potential permeability enhancement of a substrate that has been burrowed by a suite of fauna that inhabit geological firmgrounds (i.e. the Glossifungites ichnofacies) is investigated by using computer simulations, laboratory and field measurements to assess the effective permeability of a Pleistocene Glossifungites surface. All the testing methods indicate that the effective permeability of a substrate is markedly enhanced by the presence of sand-filled Glossifungites burrows in the low-permeability substrate. Furthermore, the permeability of these burrowed horizons can be well approximated by using a modified arithmetic mean that accounts for the degree of interconnectivity between burrows. These formulae are robust and, conceptually at least, can be applied to a variety of geological media and burrow configurations.

On the territory of the former Soviet Union more than 30- oil and gas-bearing basins have been defined. Among them the Precaspian basin is one of the most prolific in terms of oil and gas exploration and production. The basin is situated in the southeastern part of the East European Platform and covers an area of about 500 000 km 2 . There are a number of source rocks of different ages, among which the principal ones are Lower Permian, Middle Carboniferous and Middle Devonian marine shales and carbonates. The post-salt Mesozoic sources are of less significance. Geological and geochemical data interpretation allows the main oil/gas accumulation zones and new exploration prospects to be defined. Two main petroleum systems are recognized in the Palaeozoic sequence of the basin, containing 90% of the recoverable hydrocarbon resources: Lower Permian-Middle Carboniferous and Lower Carboniferous-Upper Devonian. The new exploration targets are deep Middle Devonian clastic reservoirs on the passive continental margins and Middle Carboniferous (Bashkirian) carbonates in the Caspian offshore part of the basin.

Studies assembling high quality datasets of fracture systems (joints and faults) from four reservoir analogues are described. These comprise limestones (Ireland), sandstones (Norway and Saudi Arabia) and chalk (Denmark). These are used with existing information from the literature to review the major controls and scaling behaviour of fracture systems expected in reservoir rocks. Lithological layering was found to be important and two end-member fracture systems have been identified. In "stratabound" systems, fractures are confined to single layers, sizes are scale restricted, and spacing is regular. In "non-stratabound systems", fractures show a wide range of sizes (often power-law), are spatially clustered and vertically persistent. In nature, variations between and combinations of these systems exist. These end-member systems have contrasting implications for fluid flow, including the scale of fracture that controls flow and the existence of a representative elementary volume, and thus on appropriate modelling approaches.

The properties and limitations of six widely used dynamic pseudo-relative permeability methods are analysed for the case of incompressible, immiscible, two-phase flow. The example proposed by Stone is used to illustrate our findings. The analytical results are confirmed by numerical simulation.

An experimental, laboratory sand model study of the origin of a decompression zone due to fluid extraction in a rock mass was carried out. It was found that an arch structure of sand density changes was formed above the decompression zone. The arch structure, which bears a portion of the load of the upper layer of the sand, can be destroyed by the action of seismic waves. The destruction of the arch causes an increase in fluid pressure in the decompressed zone. The value of the pressure increase is directly proportional to the depth of the decompression zone and inversely proportional to the dimension of the zone.

Four synthetic seismic models have been generated for an Upper Carboniferous platform carbonate-siliciclastic-evaporite succession in North Greenland. They are based on a lithological model that allows recognition of units corresponding to third-order depositional sequences. The best seismic representation of the depositional geometry is obtained in synthetic models using velocity data from the Barents Sea. They clearly show the morphology of the carbonate platforms and the onlapping siliciclastic wedges. Furthermore the distribution of anhydrite and the absorption of energy below these layers is well documented. The models also show that velocity pull-ups should be expected below dolomitized platforms whereas velocity pull-downs may record siliciclastic lenses within the platforms. The seismic models help to a better understanding of the carbonate to evaporite transitions in the Upper Palaeozoic of the Barents Sea.

An existing generic facies scheme consisting of a channel, sheetflood and floodplain facies was available from the cored wells. Bivariate and multivariate analysis of various wireline and core data indicated that each generic facies exhibits wide variations and significant petrophysical overlap with other facies. This scheme cannot therefore reliably be applied using wireline data, negating its application in uncored intervals through discriminant analysis. Due to the large variation in porosity and permeability of each facies, the existing scheme does not permit adequate determination of the probable reservoir performance of the sediments. In order to address these problems a new "litho-flow" facies scheme has been constructed which can clearly be identified from wireline data thereby enabling it to be reliably extended beyond cored intervals. Each facies in the scheme exhibits a discrete range in porosity and permeability by which the probable flow characteristics of the sediments can be assessed and has successfully been used by reservoir engineers as input to a probabilistic reservoir modelling package. Finally, the predicted facies are valid in terms of the environment of deposition, assisting geologists in the correlation of units between wells for the establishment of a depositional model. The new facies scheme was formulated from a careful selection and processing of data to achieve the above. This included core descriptions, core porosity and permeability measurements, mineral volume analysis and porosity estimation from wireline data, permeability predictions and electrofacies from cluster analysis.