Petroleum Geoscience - Volume 11, Issue 2, 2005

Integrated apatite fission track analysis and vitrinite reflectance data show that well 204/19-1 in the West of Shetland region, UK Atlantic margin, has experienced only limited additional burial beyond present-day depths. Uplift and cooling to present-day levels probably occurred during late Cenozoic (Eocene to Miocene) basin inversion. Fluid inclusion data indicate that Paleocene–Eocene sandstones have experienced temperatures much higher than can be explained by burial alone. Temperatures up to 200±°C indicate the passage of hot fluid through Cenozoic sandstones, which by-passed the pre-Cenozoic section in this and other wells. The hot fluid event must have been of very brief duration (up to 100 years) to show no record in the fission track and reflectance data, implying that the fluids migrated through fracture systems.

Oil inclusions in the Cretaceous of well 204/19-1 have a chemistry that suggests derivation from a Kimmeridgian-aged source rock. They occur in cements that show no evidence for the hot fluid event and it is concluded that the cements pre-date the event. Oil inclusions in Cenozoic sandstones have a heavy, degraded character and were trapped at high temperature, suggesting that degradation was related to the hot fluid event. Present-day oils in the West of Shetland region are mixtures, which could reflect components from the two charges distinguished by the integrated thermal and geochemical histories. The inference of fracture-bound flow is consistent with existing models of overpressure development and hydrofracturing.

The integration of 3D seismic data, well logs and synthetic seismic data has been used to identify an additional Intra Danian seismic horizon in the chalk reservoir of the Kraka Field, Danish North Sea. Mapping of this seismic horizon has allowed production of a separate thickness map for the main reservoir unit, the Danian Porous, in the greater Kraka area. The unit is less than 25 m thick in most areas and, to produce reliable reservoir maps, it has been necessary to use well data to guide the seismic interpretation. It is impossible, however, to resolve the reservoir stratigraphy properly in areas where the Danian Porous is thinner than c.15 m due to tuning effects.

The lateral porosity distribution has been mapped using a combination of well log data and seismic data inverted for acoustic impedance. The Danian Porous unit is characterized by average porosities over 28% and shows no evidence of depth-related porosity reduction. Rather, the impedance data indicate the presence of positive porosity anomalies both over the crest and downflank towards the southeast. Comparison of impedance-derived porosities with those derived from well data indicates that the seismic-based data reflect the variations in porosity but underestimate the highest porosity by 3–4%.

Faults and fractures are important for production of the Kraka Field. Detailed mapping of seismic horizons, supplemented with seismic attribute mapping, has proved useful for outlining areas with high fault intensity in the northwestern part of the field but has been unsuccessful in identifying individual faults as recognized from log data.

Low permeability cap rocks retain oil by capillary forces when the pore throats of the seals are sufficiently small to prevent a flux of oil into the cap rock. In order to investigate the influence of aquifer overpressures on oil retention, water pressure was applied to a water-wet, highly permeable (1988 mD) core sample, which was oil-saturated to irreducible water saturation S wi and mounted with a low-permeability and water-wet membrane at the outlet. A water pressure difference of 0.5 MPa was applied across the core. This pressure was high enough to ensure fluid flow through the sample. The experiment was designed to see whether the water pressure would force oil through the membrane or if capillary forces at the sandstone–membrane interface would retain the oil, in which case water flow might take place in the (residual) water in the core and through the membrane.

The experiment showed that oil was kept in place by capillary forces while water flowed through the core and the membrane. Accordingly, residual water can move through sandstones that are saturated to S wi. The experiments also demonstrated that the permeability associated with this residual water is high enough to prevent overpressures in the aquifer below the oil–water contact from pushing oil through a membrane seal. Thus, even for this highly permeable sandstone, the overpressure in the aquifer will not cause capillary seal failure.

There is a subtle controversy in the petroleum industry regarding the relationship between reservoir architecture and recovery efficiency from petroleum reservoirs. Stratigraphers tend to believe that facies architecture and geometric shapes strongly govern recovery, whereas engineers stress factors such as permeability heterogeneity and anisotropy. To understand the relationship between architecture and recovery better, a suite of conceptual models of different channelized clastic reservoir architectures was constructed and pore-volume replacement waterflood simulations were performed on each. Three 11-member suites of models were constructed at net: gross values of 35%, 60% and 85%. The reservoir architecture features that were varied were channel width to thickness, thickness, sinuosity, stacking patterns, orientation and reservoir element type (point bar vs. channel). The three sets of models appear visually very different from a reservoir architecture standpoint. Permeability and porosity were simulated using geostatistical techniques but share the same conditioning population. The same water saturation, well count (110 acre spacing), fluid properties and relative permeability were used in each waterflood simulation. In this situation, in which the only significant variable was reservoir architecture, only a few percent spread in recovery was noted for each net: gross suite. Variation in recovery efficiency can be shown to be associated with reservoir connectivity, which is generally high for all models but shows some variation. Additional studies were made to address the influence of well count, mobility ratio, permeability heterogeneity and geostatistical seed number on recovery efficiency.

Two stratigraphic factors are shown to influence recovery efficiency: reservoir connectivity and permeability heterogeneity. Both factors influence the volumetric sweep efficiency of reservoirs. Models that appear to be visually different, but have similar connectivity, well count and permeability heterogeneity, have similar sweep efficiencies and, therefore, recovery efficiencies. The practical importance of this observation for development studies is that building and flow-simulating suites of models with different reservoir architectures may not help to characterize recovery uncertainty unless the models are constructed to emphasize differences in sweep efficiency.

New seismic reflection data have been used to image intra- and sub-basalt features beneath the Faroe–Shetland Basin in the North Atlantic, where the highly reflective top and base boundaries of flood basalts and their complex internal structure make successful seismic imaging difficult. This study demonstrates that appropriate acquisition and processing of marine seismic data from hydrophone streamers and ocean-bottom seismometers (OBS) has the potential to enhance significantly imaging of intra-basalt and sub-basalt seismic reflections. The intersection of a new seismic reflection profile recorded in 2002 with a seismic profile recorded in 1998 allows a direct comparison of advances in sub-basalt imaging over this period and an interpretation of geological structures and seismic velocities at the intersection.

To achieve better resolution of sediments below basaltic layers, surface seismic reflection data using a broad-band, low-frequency source have been recorded. By using a source wavelet with a significantly enhanced frequency spectrum centred at 10 Hz, generated from a large (167 l) airgun array tuned to the first bubble pulse, a wavelet is produced that is capable of penetrating through thick basaltic sequences. Furthermore, recording the low-frequency reflections to large offsets along a 12 000 m long streamer with 3.125 m single sensor spacing allowed effective suppression of multiple reflections, enhanced the precision of velocity analyses and produced better migration results. Seismic data along the same profile were also recorded on a dense deployment of 85 four-component OBS at 2 km or 6 km station spacing. These complementary ocean-bottom data allowed the large-scale velocity variations within and beneath the basalt to be constrained by recording at large offsets the termination of the diving rays (c. 18 km) propagating through the basalt.

Integration of seismic reflection data and OBS recordings yields good seismic velocity estimates and, therefore, increased confidence in the interpretation of intra- and sub-basalt features and lithology. Four major stratigraphic units characterized by their seismic velocities and reflection characters were identified: (a) post-basalt sediments; (b) basalt sequence; (c) sub-basalt unit; and (d) the top of presumed Cretaceous basement. The top boundary of the basalt sequence is defined by a strong reflection with a steep velocity increase from 3.5 km s−1 to 4.5 km s−1 in the c. 200 m thick layer above it. The basalt sequence here is c. 2.5 km thick. Beneath the base of the basalt there is a velocity decrease from 5.8 km s−1 to 5.2 km s−1. The sub-basalt unit is subdivided further into hyaloclastites mixed with sediments and sills, and sub-basalt sediments separated by another velocity inversion from 5.2 km s−1 to 4.5 km s−1. The Cretaceous basement with velocities above 5.5 km s−1 lies underneath these sub-basalt sediments.

A systematic analysis of petroleum system criticals can provide a robust review of a basin's hydrocarbon potential through time and space. The ten essential petroleum system criticals that express the extensive and intensive variables are: source generation volume (Sgv), source-rock richness (Sgr), source-rock quality (Srq), source-rock maturity (Srm), reservoir rock volume (Rrv), reservoir rock quality (Rrq), reservoir rock hydrocarbon type (Rrhct), reservoir rock seal and closure (Rrsc), flux migration path (Fmp) and petroleum system timing (PSt). The Matruh–Shushan Basin of the Western Desert, Egypt, forms the basis for an example of the application of this technique.

Modelling and empirical data of source-rock criticals reveal that the Mesozoic source generation megasequence is restricted in the Matruh–Shushan Basin. Presently, these areas lie buried at their maximum experienced temperatures. Potential reservoirs in portions of the north and central Western Desert were dependent upon lateral migration path criticals for their charge. Progressive uplift and basin inversion since the middle Palaeozoic provided favourable conditions for lateral migration in the Mesozoic. The main potential source rocks in the present basins are the Lower Cretaceous Alam El Bueib (AEB) and the Jurassic Khatatba. Although both share mixed kerogen types (II/III), they attained their highest levels of thermal maturity at different times. Basin modelling suggests the Lower Cretaceous AEB entered the oil window in the Late Cretaceous, while the Jurassic Khatatba of the deeper part of the basin entered the oil window in the Turonian.

Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower post-Late Cretaceous structured reservoirs.

Basin modelling incorporating an analysis of the petroleum system criticals has outlined the spatial and temporal extent of the different petroleum systems in the Matruh–Shushan Basin and can help guide the next exploration phase. While oil exploration is now focused appropriately along Late Cretaceous and Tertiary migration paths, these results suggest deeper sections may have reservoirs charged with significant unrealized gas potential.

The assessment of petroleum resources of the North Sea, as well as other areas of the world, requires a viable means to forecast the amount of growth of reserve estimates (reserve growth) for discovered fields and to predict the potential fully developed sizes of undiscovered fields. This study investigates the utility of North Sea oil field data to construct reserve-growth models. Oil fields of the North Sea provide an excellent dataset in which to examine the mechanisms, characteristics, rates and quantities of reserve growth because of the high level of capital investments, implementation of sophisticated technologies and careful data collection. Additionally, these field data are well reported and available publicly.

Increases in successive annual estimates of recoverable crude oil volumes indicate that oil fields in the North Sea, collectively and in each country, experience reserve growth. Specific patterns of reserve growth are observed among countries and primary producing reservoir-rock types. Since 1985, Norwegian oil fields had the greatest volume increase; Danish oil fields increased by the greatest percentage relative to 1985 estimates; and British oil fields experienced an increase in recoverable oil estimates for the first ten years since 1985, followed by a slight reduction. Fields producing primarily from clastic reservoirs account for the majority of the estimated recoverable oil and, therefore, these fields had the largest volumetric increase. Fields producing primarily from chalk (limestone) reservoirs increased by a greater percentage relative to 1985 estimates than did fields producing primarily from clastic reservoirs. Additionally, the largest oil fields had the greatest volumetric increases. Although different reserve-growth patterns are observed among oil fields located in different countries, the small number of fields in Denmark precludes construction of reserve-growth models for that country. However, differences in reserve-growth patterns among oil fields that produce from primarily clastic and primarily chalk reservoirs, in addition to a greater number of fields in each of the two categories, allow separate reserve-growth models to be constructed based on reservoir-rock type.

Reserve-growth models referenced to the date of discovery and to the date of first production may be constructed from North Sea field data. Years since discovery or years since first production are used as surrogates for, or measures of, field-development effort that is applied to promote reserve growth. Better estimates of recoverable oil are made as fields are developed. Because much of the field development occurs some time later than the field discovery date, reserve-growth models referenced to the date of first production may provide a more appropriate measure of development than does date of discovery.