Ole Petter Wennberg

Fracture intensity vs. mechanical stratigraphy in platform top carbonates: the Aquitanian of the Asmari Formation, Khaviz Anticline, Zagros, SW Iran

Outcrop analogue studies can significantly improve the understanding of fracture distribution and their impact on fluid flow in hydrocarbon reservoirs. In particular, the outcrops may reveal details on the relationships between mechanical stratigraphy and fracture characteristics. This has been investigated in an integrated sedimentological-structural geological study in the Aquitanian sequence of the Asmari Formation on the NE limb of the Khaviz Anticline in the Zagros foothills in SW Iran. The Aquitanian sequence was deposited in a platform top setting and is characterized by well-defined bedding planes and relatively thin layers (<4 m) with rapid changes in textures from laminated peritidal mudstones to bioclast and ooid grainstones. Fractures in the studied area dominantly strike parallel to the fold axis, have a high angle to bedding and are stratabound. In the literature it is often reported that fracture spacing or the inverse fracture intensity (FI) is controlled by the mechanical layer thickness (MLT). However, in the present study area a rather poor correlation between FI and MLT was observed. Instead, the Dunham texture appears to be more important for the FI. Mud-supported textures (mudstone and wackestone) have higher FI than grain-supported (packstone and grainstone) ones. The degree of dolomitization does not appear to have any significant effect on FI within each texture class. A strong relationship between FI and MLT is observed generally in cases where there has been one single phase of extension and when interbed contacts are weak, e.g. interbedded competent limestones and incompetent shales. However, in the present study area a rather complex deformation history exists and well-developed shales between fractured carbonate layeres are lacking. It is suggested that in such cases the MLT is of minor importance for the FI, which is controlled by the texture.

The Khaviz Anticline: an outcrop analogue to giant fractured Asmari Formation reservoirs in SW Iran

Abstract The carbonate reservoirs in the Late Oligocene—Early Miocene Asmari Formation in the Dezful Embayment of SW Iran are characterized by low matrix permeability, and effective drainage is dependent on the occurrence of open fractures. Limited information on fracture orientation and fracture density is available from core and borehole image data, and high-quality/high-resolution three-dimensional seismic is often lacking in this area. Well and core data do not contain information on important fracture parameters like length distribution, crosscutting relationships, fracture density v. lithology and bed thickness. The understanding of fracture distribution and formation in the region and their effects on fluid flow has been greatly improved by the use of outcrop analogue data. Exposures of the Asmari Formation in the Khaviz Anticline are in close vicinity to the giant hydrocarbon fields. The Khaviz Anticline has a similar geometry and structural history to the major hydrocarbon fields in the area, and represents an excellent analogue for these. Two types of fracture features were observed: diffuse fracturing and fracture swarms. The diffuse fractures form networks and comprise structures grouped into four fractures sets, which are the typical for this type of anticline. Two orthogonal fracture sets are oriented parallel and perpendicular to the fold axis, and two conjugate fracture sets are oblique to the fold axis with their obtuse angle intersecting the trend of the fold axis. The fractures are typically stratabound, sub-perpendicular to bedding and commonly about the bounding stratigraphic surfaces. To a large extent the density and height of fractures in the Asmari Formation are controlled by the mechanical stratigraphy, which is controlled by the depositional environment and cycles. These outcrop data have been essential in the generation of discrete fracture network (DFN) models and the population of the fracture properties in the reservoir models.

On the occurrence and formation of open fractures in the Jurassic reservoir sandstones of the Snøhvit Field, SW Barents Sea

Open fractures were described in core and Formation Micro Image (FMI) image logs in the Jurassic sandstones of the Tubåen, Nordmela and Stø formations in the Snøhvit Field, and 3D fracture network properties analysed using Computer Tomography (CT)scanning in selected core samples. The most frequent open fracture type is short stylolite-related fractures (F1), but longer open fractures are also present, with no obvious relationship to stylolites (F2). The F1 fracture densities are related generally to the clay content of the host rock, which controls the occurrence and spacing of the stylolites. The fractures are steep, with a N–S-dominant strike azimuth and significant spread. Although, generally, the F1 fractures are short, a percolating and 3D connected open fracture network across the core was found in most of the CT-scan samples. Open fractures were also found in the damage zone of a lately reactivated fault. The formation of the open fractures in the Snøhvit Field is related most likely to thermoelastic processes during removal of overburden in late Tertiary time. The presence of open fractures may influence reservoir flow, particularly in intervals containing a high frequency of stylolites and in the damage zones of reactivated faults.

The characteristics of fracture networks in the Shiranish Formation of the Bina Bawi Anticline; comparison with the Taq Taq Field, Zagros, Kurdistan, NE Iraq

The Zagros Fold and Thrust Belt of NE Iraq hosts a prolific hydrocarbon system. Reservoirs are commonly found in fractured Cretaceous carbonates (Shiranish Formation) such as in the Taq Taq Field located in the Kirkuk Embayment of the Zagros foothills. Data providing information on fractures in the Taq Taq Field are core, image logs and flowmeters from wells, and surface observations. For comparison, an outcrop study has been undertaken around the Bina Bawi Anticline (10 km from Taq Taq Field), where the same stratigraphical unit is exposed in a continuous, lenticular-shaped belt. Fracture data have been collected using scanlines on bedding surfaces in the limbs and hinge of the anticlines. Both the Bina Bawi Anticline and Taq Taq Field show a systematic relationship between fracture sets and fracture lineaments, with a dominance of NE–SW-oriented structures. This orientation is perpendicular to the major folds and parallel to the maximum horizontal in situ stress. There are three fracture populations in the Bina Bawi Anticline, classified according to their relationship with the fold axis and bedding: (i) NW–SE-striking fractures normal to bedding: (ii) NE–SW-striking fractures normal to bedding; and (iii) conjugate oblique fracture sets subnormal to bedding. Both fracture intensity and fracture terminations are controlled by the location within the anticline; the hinge zone displays the highest intensity and the most fracture-abutting terminations. Cross-cutting relationships suggest that a prefolding stage of NE–SW tensional fractures predates folding-related tensional and shear fractures. Few uplift fractures can be indicated. We propose that the former fracture set (joints) formed in a foreland setting and was controlled by the far-field stresses, whereas later fracturing occurred due to outer arc extension during flexing of the Bina Bawi and Taq Taq anticlines. Our comparative analysis of outcrop and well data underline the importance of representative analogue data for reservoir modelling and production strategies.

The characteristics of open fractures in carbonate reservoirs and their impact on fluid flow: a discussion

Permeability in fractured carbonate reservoirs is very heterogeneous due to fracturing at different scales superimposed on inherent textures from deposition and diagenesis. Observations of fractures in core and outcrop indicate that flow in open fractures in carbonate rock tends to be channelled rather than through fissures. Most of the flow takes place along a few dominating channels in the fracture plane, whereas most of the fracture plane is not effective for fluid flow. The formation of flow channels is caused by a combination of mechanical and, in particular, diagenetic processes. Single extension fractures occur as partly open or vuggy fractures, and their hydraulic properties are controlled by dissolution and cementation. Single shear fractures are typically open at local steps in the fault plane controlled by shearing along irregular fracture surfaces. Fault damage zones tend to be concentrated at fault tips, intersections, pull-aparts and overlap zones that represent areas of dilation. These damage zones represent elongated features in three dimensions with a high fracture density that will result in channelled flow at reservoir scales. The effect of channelled flow should be taken into account during evaluation of fractured carbonate reservoirs and when building dynamic flow models.

Well-data-based discrete fracture and matrix modelling and flow-based upscaling of multilayer carbonate reservoir horizons

Abstract Discrete fracture and matrix (DFM) homogenization, simultaneously capturing reservoir layers and contained fractures, is an alternative to discrete fracture network (DFN) upscaling. Here, the DFM approach was applied to a fractured carbonate reservoir. Honouring geostatistical data from well logs, near-well multilayer reservoir models were constructed and analysed. Fracture aperture variations were modelled with a new semi-analytical model including a special treatment of layer-restricted fractures. Important results concern both pre-processing of stochastically generated DFMs for finite-element meshing, and the ensemble permeability values obtained by numerical homogenization of single v. multilayer models, respectively. Upscaling by volume averaging of vertically stacked single-layer DFMs results only in a fraction of the equivalent horizontal permeability that is obtained by homogenization of the multilayer models. Inspection of the flow patterns shows that this discrepancy arises because many fractures contact each other at layer boundaries fostering cross-flow. This effect is further enhanced where fractures intersect multiple layers. Compared to earlier DFN models for this reservoir, the DFM-derived fracture and matrix ensemble permeabilities are up to four times higher, highlighting how important it is to include the rock matrix into equivalent permeability calculations.

A brief introduction to the use of X-ray computed tomography (CT) for analysis of natural deformation structures in reservoir rocks

Abstract X-ray computed tomography (CT) is frequently used for non-destructive imaging and analysis of internal features in rock samples. In this paper we review the method for analysis of subseismic deformation structures in reservoir rocks, and provide some examples of different types of structures. Both medical CT and high-resolution µCT have great potential for identification of small-scale deformation structures in reservoir rocks and samples from outcrop analogues. The CT imaging techniques provide 3D data that are used in combination with 2D information from core or outcrop, thin-section and scanning electron microscopy (SEM). CT and µCT are used for quantitative and qualitative analysis of individual fractures and fracture networks, and for imaging and analysis of internal heterogeneities of fault rocks and deformation bands. The benefit of CT is that 3D properties (e.g. structure size, connectivity and variation in aperture) are actually characterized in 3D, contrary to traditional 2D methods using core surface, thin-section and outcrop. Limitations and uncertainties arise from artefacts during acquisition and processing, scale of observation and resolution, and manual steps involved in the segmentation of the CT volume. Increased availability of medical CT and µCT scanners and improved resolution should in the future lead to improved description and modelling of small-scale reservoir structures.

Fractures in Chalks and Marls of the Shetland Group in the Gullfaks Field, North Sea

Summary Oil production from the Shetland Group of the Gullfaks Field in the Northern North Sea is controlled by the presence of natural fractures. The fractures and the fracture network have been characterized using core description, thin section and CT analysis. The Shetland Group consist of interbedded chalk, marl and mudstone beds. Fracture distribution is controlled by the mechanical stratigraphy; shear fractures are most developed in the marls and tensile fractures in the chalk. Fracture density tends to be highest in chalks with low porosity. Open fractures are partly filled with calcite cement forming bridges between the fracture walls and/or lining on the fracture surfaces. The distribution of mechanical fracture aperture in 3D has been estimated along the fracture plane. The detailed fracture characteristics will be further used to address the micro-scale sweep efficiency and the geomechanical effects on single and two-phase fluid flow.

Characterisation Of Natural Open Fractures In Carbonates Using X-Ray Computed Tomography - Examples From Shetland Group I

A large proportion of carbonate reservoirs contain natural open fractures, which have a significant impact reservoir fluid flow and ultimate recovery. In this study, high resolution X-ray computed tomography (μCT) has been used for imaging, interpretation and analysis of open fracture in carbonate in true 3D. The samples are form the Shetland Group in the Gullfaks Field, which has produced oil since late 2012. The μCT data shows that the tensile fractures occur as calcite veins or are partly filled with calcite cement. Fractures tend to be most frequent in low porosity parts of the formation, and bioturbations also have a significant effect on the shape, orientation and occurrence of fractures. The μCT gives the detailed geometry and aperture distribution of the fractures in 3D.