Petroleum Geoscience - Volume 5, Issue 3, 1999

A time lapse analysis was performed on two 3D seismic datasets (4D seismic) acquired over the northern part of the Gullfaks oilfield in the North Sea. The first survey was acquired in 1985, prior to the production start in 1986, a second survey was acquired in 1995, followed by a third in 1996. The drainage interpretations carried out by means of the repeated seismic datasets are in reasonable agreement with similar interpretations performed the traditional way by reservoir engineers, and have locally resulted in an improved understanding of drainage. The time lapse seismic data are routinely used in well planning projects on Gullfaks. In 1997, two wells were drilled into segments that, based on repeated seismic data, were interpreted to be undrained. Both wells encountered oil-filled reservoirs. Although these wells were not based on time lapse seismic alone, the wells served as a good test of the reservoir management potential associated with the 4D technology. Furthermore, waterfront movements predicted on the basis of time lapse seismic data are confirmed by well observations.

An important issue in petroleum engineering is the prediction of gas production during reservoir depletion--either following conventional waterflooding operations or in the early stages of hydrocarbon production. The estimation of critical gas saturation for use in corresponding simulation studies is clearly a primary concern. To this end, a 3D, three-phase numerical pore-scale simulator has been developed that can be used to estimate critical gas saturations over a range of different length scales and for a wide range of fluid and rock properties. The model incorporates a great deal of the known physics observed in associated laboratory micromodel experiments, including embryonic nucleation, supersaturation effects, multiphase diffusion, bubble growth/migration/fragmentation, oil shrinkage, and three-phase spreading coefficients. The precise pore-scale mechanisms governing gas evolution have been found to be far more subtle than earlier models would suggest because of the large variation of gas/oil interfacial tension (IFT) with pressure. This has a profound effect upon the migration of gas structures during depletion. In models pertaining to reservoir rock, the process of gas migration is consequently much slower than predictions from more simplistic models would imply. This is the first time that bubble fragmentation and IFT variations have been included in a model of gas evolution at the pore-scale and the implications for production forecasting are expected to be significant. In addition, novel scaling groups have been derived for a number of different facies under both virgin and waterflooded conditions. One future application of these groups would be to scale S gc values obtained from high rate depressurization experiments to the low rate conditions more characteristic of field operations.

Five formation tests were undertaken in well 110/8A-5 in the Irish Sea. Pressures within the tested intervals were reduced from 16-17 MPa to c. 10 MPa. The tested intervals, which were subsequently logged by an electrical imaging tool, exhibit zones of low resistivity on opposite sides of the wellbore wall. These zones are restricted to the tested intervals and interpreted as borehole breakouts. It is inferred that the reduction in wellbore pressure associated with testing increased the stress acting on the wellbore wall, leading to failure. This confirms that such wellbore failure can be induced by reducing mud weight. Maximum horizontal stress is inferred to be orientated east-west which has implications for reservoir development, because natural and induced fluid flow will tend to be focused in that direction. With regard to the formation tests, near wellbore fracturing may result in modelled permeabilities exceeding those associated with intact reservoir rocks.

Based on detailed analyses of seismic and well data, the Statfjord Field, northern North Sea, can be separated into a relatively undeformed main field area and an east flank heavily deformed by rotational block slides. The main tectonic event is related to the opening of the Viking Graben which started in the middle Jurassic and which increasingly affected deposition of the Bathonian-Oxfordian Heather Formation. This rift phase peaked before the deposition of the Draupne Formation causing gravitational instabilities along the crest of the field and subsequent rotational block slides in the Upper Triassic and Jurassic sections. Compared to fields closer to the graben centre only limited erosion affected the Statfjord Field reservoirs during the Oxfordian-Ryazanian. Here, the Draupne Formation still drapes a partly degraded Jurassic sequence and is thickest on the west flank and within topographic depressions on the east flank. Minor tectonic activity occurred during the Cretaceous and Tertiary.

A correlation between oil rates and earthquakes was observed in the 1970s. It resulted in the first attempts to use the energy of seismic waves to mobilize residual oil spread in the reservoir in the form of drops of different sizes, and to rehabilitate depleted oil fields with high water production. Laboratory tests showed that oil displacement can be increased by application of low-frequency vibration. It was also confirmed by field tests (results reported at VI EOR ES, 1991): oil production due to vibroseismic stimulation increased by 30-40%. However, estimations show that such an increase in oil production does not occur with low-frequency vibration. Most probably some unknown phenomena exist which impact on the mechanism of seismic vibration-induced increases in oil production. The object of this study was the development of an analytical model of vibroseismic stimulation to explain the mechanism of residual oil mobilization. Such a model can provide the basis for effective use of vibration stimulation. The model oil-saturated formation consists of blocks of different sizes. Each large block includes several blocks of smaller sizes. Block sizes depend on the geological processes taking place during their formation, while correlation between their sizes does not depend on properties of constituent materials. Core measurements taken in the millimetre range and analysis of photographs of layer distribution in open hole taken in the metric range show that correlation between the large and small blocks occurs over a rather small range and varies between 2.91 and 3.43. Simulation of vibroseismic impact on a formation shows that a process of low-frequency energy transfer from larger blocks to smaller ones, producing high-frequency vibration, takes place. These high-frequency vibrations provide conditions under which capillary forces, retaining oil drops in the porous media, are destroyed, improving conditions for oil mobilization. These results agree with experimental data of noise measurements recorded during pilot commercial tests of vibroseismic action at different oil fields in Russia. Thus the possibility of residual oil mobilization by applying low-frequency vibroseismic stimulation was confirmed both theoretically and in laboratory and field tests. The results received were an essential part of the creation of the technology for vibroseismic stimulation of waterflooded, depleted oil reservoirs.

Fractured wells are frequently encountered in petroleum engineering. They can be hydraulically fractured wells to improve oil production or wells intersecting natural fractures. Due to the presence of the fractures, the flow behaviour and the pressure distribution in the vicinity of the fractured well are complex and the numerical modelling for this kind of well is complicated. There are no efficient numerical methods to simulate these wells, especially for the fractured horizontal or multi-lateral wells. In this paper, we discuss the new techniques for fractured well simulations using the reservoir simulator. A new method, which is based on the calculation of suitable numerical PI at the well blocks and of transmissibilities around the fractured wells according to the steady-state pressure distribution, is proposed for fractured well modelling. This method can provide satisfactory results with coarse grid simulations.

3D seismic data provide images of geological features which are approximately circular in plan view but whose shape and origin may not be possible to constrain using 2D seismic data. As 3D seismic data become more commonly employed in hydrocarbon exploration, the number of demonstrably "circular" structures will increase. At least ten different geological processes can result in seismically resolvable "circular" structures in sedimentary basins. These include salt/shale diapirs, salt withdrawal basins, polygonal fault blocks, dissolution collapse hollows, breccia pipes, calderas, gas pockmarks, bioherms, sand volcanoes, pull-aparts, impact craters and tectonic folds. Geometrical and geological criteria for each are summarized to facilitate identification of such features should they be encountered in the course of a 3D seismic interpretation. Certain types of geological feature have distinctive properties, others are less straightforward to recognize on the basis of individual criteria.

The scale of heterogeneities in reservoirs is often smaller than the grid size used in large-scale reservoir simulations. Relative permeabilities have the foremost effect on fluid flow and small-scale fractional flow must be upscaled to the grid size in flow simulations. Thus, systems with fractional flow heterogeneities, i.e. relative permeability variations, have to be solved and effective relative permeability functions determined. In this paper, benchmark analytical solutions are developed for a system consisting of two media in series where each medium is characterized with a different set of relative permeabilities, residual saturations and porosities. The analytical solutions show a significant discontinuity in the saturation and concentration profiles at the interface of the two media. Numerical results using several weighting schemes are compared against the analytical solutions for two-phase immiscible and partially miscible systems. It is shown that single-point upstream weighting requires about 100 grid blocks to capture the discontinuity at the interface, whereas third-order TVD weighting requires much fewer. Lastly, the validity of the JBN method and harmonic averaging for determination of effective relative permeabilities and overall pressure drop is tested. Both the JBN method and harmonic averaging cannot reproduce the pressure drop across the composite media prior to water breakthrough.

Nd-Sr data indicate that two isotopically distinct terrains supplied sediment to the Upper Carboniferous basins of Britain. One terrain was relatively depleted in radiogenic Nd, and included large areas of old continental crust; the other was less depleted in radiogenic Nd and is thought to have included a significant amount of first generation juvenile material that was added to the older crust during the early Palaeozoic continental collisions. The isotopic signatures reflect the average composition of the crust from which the Carboniferous sediments were originally derived. In multicyclic, multiorogenic settings such as NW Europe, understanding the geographic distribution patterns of the sediment can only be accurately ascertained by employing a combination of provenance characterizing techniques (isotopes/palaeocurrents/heavy minerals). Here, combined results indicate that the first terrain lay in Laurentia, whereas the other was a large region bordering the north side of Gondwana, and including Avalonia and Armorica.

A detailed time-structure map of Top Chalk in the eastern Danish North Sea is presented, based on conventional seismic and well data, and 5800 km of new multi-channel, high resolution seismic data. Several factors influenced the present-day topography of Top Chalk at various scales: Cenozoic regional differential subsidence/uplift, reactivation of late Palaeozoic-Mesozoic structures, salt structures in the Norwegian-Danish Basin, collapse structures along the Ringkobing-Fyn High, mounds on the Ringkobing-Fyn High, erosional valleys, and possible karstification in parts of the Norwegian-Danish Basin. Erosional valleys and karst topography suggest that the Top Chalk was subaerially exposed in the eastern North Sea in mid-Paleocene times. The valleys probably acted as conduits for deposition of potential reservoir sands in the middle to late Paleocene. The interpretation of karst topography indicates that carbonate dissolution may have affected the reservoir properties of the uppermost part of the Chalk Group in the eastern North Sea.