Petroleum Geoscience - Volume 14, Issue 4, 2008

A compilation of average porosity and permeability data for Cretaceous petroleum reservoirs of the Middle East reveals important differences between the two main tectonic provinces. The Arabian Platform is characterized by inverse correlation of average porosity with burial depth in both carbonates and sandstones, whereas the Zagros Fold Belt (almost exclusively carbonates) has distinctly lower porosity and no depth correlation. These contrasts are suggested to reflect the fact that Arabian Platform strata are mostly near their maximum burial depth, whereas Zagros strata have experienced varying uplift and erosion following maximum burial in mid-Tertiary time. The carbonate reservoirs show no correlation between average porosity and average permeability, probably because of wide differences in the dominant pore types present, and permeabilities tend to be much higher for sandstones than for carbonates.

Existence of the Arabian Platform porosity–depth correlation, despite an apparently wide diversity of depositional settings and early diagenetic porosity modifications among the individual reservoirs, illustrates and confirms some fundamental generalities about how burial diagenesis controls the overall porosity evolution of reservoir rock bodies. Although porosity commonly shows enormous small-scale heterogeneity in both carbonates and sandstones, the average pre-burial porosity of larger stratigraphic intervals tends to be very high. Burial diagenesis progressively destroys this porosity by chemical compaction and associated (stylolite-sourced) cementation. Thus, all portions of the affected rock body move toward the zero limit as depth increases, although the rates of porosity occlusion vary greatly, depending on rock fabric and early diagenesis. Average reservoir porosity therefore tends to correlate inversely with maximum burial depth, regardless of initial lithological heterogeneity.

This study determines the relationship between permeability and other petrophysical properties in synthetic mudstones as a function of vertical effective stress. Six brine-saturated clay slurries consisting of smectite and kaolinite were compacted in the laboratory under both controlled pore pressure and proper drained conditions. Porosity, permeability, bulk density, velocity (both Vp and Vs ) and rock mechanical properties were measured constantly under increasing vertical effective stress up to 50 MPa. The results show that smectite-rich clays compact significantly less and have lower bulk density, velocity, permeability, bulk and shear modulus but higher Poisson's ratio compared to kaolinite-rich clays at the same effective stress. Kaolinite aggregates compacted to about 26% porosity at 10 MPa effective stress corresponding to about 1 km burial depth in a normally compacted basin, whereas a pure smectite aggregate has a porosity of about 46% at the same stress. The permeability of kaolinite aggregates varies between 0.1 mD and 0.001 mD, while that of smectite aggregates varies from 0.004 mD to 0.00006 mD (60 nD) at stresses between 1 MPa and 50 MPa. Permeabilities in clays show a logarithmic decrease with increasing effective stress, bulk density, velocity or decreasing porosity. At the same porosity or bulk density, permeabilities differ up to five orders of magnitude within the smectite–kaolinite mixtures. Applications of the Kozeny–Carman equation for calculating permeability based on porosity in mudstones will therefore produce highly erroneous results. The relationships between Vp , Vs , bulk and shear modulus to permeability also vary by up to four orders of magnitude depending on the clay compositions. Velocities or rock mechanical properties will therefore not be suitable to estimate permeability in mudstones unless the mineralogy and textural relationships are known. These experimental results demonstrate that smectite content may be critical for building up pore pressure in mudstones compared to kaolinite. The results help to constrain compaction and fluid flow in mudstones in shallower parts of the basins (<80–100°C) where mechanical compaction is the dominant process. These results may also have implications for waste disposal and engineering practice, including structural design and slope stability analysis.

The benefits of seismic attribute classification in subsurface studies have been published widely. The approach is usually the same and, in most cases, driven by a two-step procedure – an unsupervised classification and a supervised scheme where training is used to redefine classes based on well-log data flagging a specific fluid or lithology. In parallel to the multi-attribute analysis, interpreters have also benefited from recent advances in computing power, enabling the generation of multi-trace or texture attributes.

In these two workflows, the focus is either on the seismic texture facies for seismic stratigraphic purposes, or on the reservoir facies for fluid and lithology mapping. This paper presents a case study in which both texture facies and fluid prediction are linked by performing a hierarchical classification scheme whereby a multi-attribute-based volume, which captures seismic texture information, is combined with amplitude versus offset (AVO) attributes to map fluid response into a single, coherent reservoir facies volume. This methodology is then applied for exploration data screening in offshore Borneo in the Greater Samarang sub-block (East Baram Delta, offshore Sabah, Malaysia). In this case study, the geological analysis, seismic geomorphology, seismic stratigraphy and combined fluid response from AVO attributes facilitate the development of new play concepts in the highstand system tracts and in the morphology generated by incised valleys in shoreface deposits.

The first section of the paper focuses principally on the analysis of four wells located west of Shetland, UK to demonstrate that the appropriate use of AVO (amplitude versus offset) analysis forms a worthwhile and valuable tool for exploration. The wells analysed include two with hydrocarbons, the Foinaven oil well 204/24a-2 and the Laggan gas field discovery well 206/1-2, and two wells positioned on amplitude-related prospects (204/17-1 Fleet North Prospect and 204/18-1 Assynt Prospect). Both 204/17-1 and 204/18-1 failed to find hydrocarbons, where the previous work indicated mainly a Class III AVO anomaly. However, these studies demonstrate that both the amplitude anomalies conform to a Class I AVO. For the hydrocarbon-bearing reservoirs encountered in both the 204/24a-2 and 206/1-2 wells, the results confirmed the presence of Class III AVO anomalies.

A second aspect to this paper centres on the application of spectral decomposition to the seismic data relating to these four wells, which provides further evidence that there are also apparent differences in the spectral characteristics between them. Both Foinaven and Laggan exhibit Class III AVO anomalies, which are consistent with the theoretical predictions for frequency-dependent AVO behaviours. However, the results from the 204/17-1 and 204/18-1 wells show rather complicated behaviour in the iso-frequency sections that cannot be explained fully. In summary, though the amplitude anomalies seen in the two prospect wells were interpreted originally to be similar to that in Foinaven, this study demonstrates they are different in both their AVO behaviour and spectral characteristics.

This paper presents results obtained from an area located east of Bremen, Germany, where gas is produced from a deep Rotliegend sandstone reservoir. Faults, fractures and associated deformation bands at reservoir depth have an important influence on the productivity of the gas field as fractures are cemented and tight and may act as permeability barriers. This contribution comprises the development of new coherency tools to better image sub-seismic faults and lineaments from seismic data, and the development of fracture attributes in order to quantify fracturation and its areal distribution.

The fractal behaviour of faults was used to establish a relationship between coherency processed seismic data and borehole images at log scale. The ‘fractal dimension’ (FD) of the length of a fault population can be interpreted as a characteristic parameter describing local geology in terms of fracturation. Calculating FD for each point of a seismic grid yields an areal distribution of this value. Correlating seismic-derived FD values and fracture populations derived from borehole images defined a linear relationship which can be used to forecast the distribution of sub-seismic fractures and deformation from seismic data.

Little is known about the nature of faults that cut the Triassic Argilo-Gréseux Inferieur reservoir of the Berkine Basin, Algeria. To rectify this, an analysis was performed of faults in the Ourhoud Field in terms of their geometry, connectivity and fault sealing potential. Different oil–water contacts had been identified across the field, suggesting a degree of fault compartmentalization. Fault-rock material from cored wells in the Ourhoud Field was analysed to determine the type, permeability and capillary threshold pressure. The suite of fault rock present is highly varied, ranging from disaggregation faults and cataclasites in clean sands to clay smears. All the fault rocks have lower permeabilities and higher capillary threshold pressures than the undeformed host rock of the Triassic Argilo-Gréseux Inferieur. The observed oil–water contact and pressure differences can all be supported by the dominant fault rocks if their clay content exceeds 20%. Fault-rock data were also used to generate transmissibility multipliers for incorporation into the Ourhoud geological and simulation models. Significant reductions in transmissibility multiplier are generated by more clay-rich fault rocks separating reservoir units with permeabilities ranging from 10 mD to 1000mD.

Layer-bound systems of polygonal faults are found in sequences of very fine-grained sediments that have typically undergone passive subsidence and burial. In the absence of tectonic extension, the heave of the faults must be complemented by horizontal compaction of the sediments. Density inversion, syneresis and low coefficients of friction on fault planes have all been proposed as causal mechanisms for the development of polygonal fault systems, but most sequences that contain polygonal faults are not underlain by sediments of lower density and there is a lack of evidence to support the idea that syneresis is responsible. Laboratory measurements of clay properties and a recent field test based on well data strongly suggest that low coefficients of residual friction in fine-grained sediments are key to the growth of faults that eventually develop into polygonal systems. However, coefficients of residual friction apply to faults only after initial slip has taken place, so some other mechanism must be responsible for the initial nucleation of the faults. Various speculative suggestions have been made, but there is no evidence that nucleation of those faults that evolve into polygonal systems differs fundamentally from the processes involved in the nucleation of other faults in soft sediments.

The conventional compaction model used in reservoir simulators defines compaction as a function of fluid pressure, whereas, in reality, it is a function of effective stress. The interrelationship between fluid pressure, effective stress and reservoir parameters (materials distribution, geometry, production scheme) is investigated. By modifying the conventional concept of flow simulator compaction a predictor is constructed for the rock mechanics computations in a coupled flow–rock mechanics simulation. This predictor reduces the time to converge the stress computations by reducing or eliminating the number of pore volume iterations in the coupling scheme. Overall computing time is thereby reduced considerably, while maintaining accuracy in the stress computations. Additionally, the compaction state in the flow simulator will be more accurate than in a conventional iterative coupling scheme.