Understanding the density, distribution, and geometry of fractures is vital for successful modeling of fractured reservoirs. RDR is able to combine a detailed analysis of available data (core, borehole image, seismic, and well test data) with outcrop analogue mapping and geomechanical modeling to predict fracture distribution around the reservoir. This information can be used to condition and improve DFN and flow models. RDR has experience of applying these techniques to shale, carbonates, tight sandstones and igneous and metamorphic fractured reservoirs.
- RDR has carried out detailed structural logging of more than 80 km of core from different lithologies around the world.
- Detailed logging of fracture type and fill can differentiate fractures that contribute to flow in the subsurface and fractures that act as flow barriers. This can be calibrated against mud loss, well test, and production logging data.
- Geostatistical analysis of fracture density and type against lithology, stratigraphy, and well location determine the key controls on fracture density and can be used to predict fracture density and away from well control.
- Microstructural analysis using SEM and XRD can determine diagenetic history and the timing of fracture development relative to hydrocarbon migration.
Borehole image interpretation
Borehole images have three key advantages in analyzing fractured reservoirs:
- They are cheaper to acquire than core and can hence be acquired over longer intervals in more wells.
- They image the fractures in situ, showing whether they are open or closed in the subsurface.
- They are oriented, enabling the predominant fracture orientation(s) to be determined.
RDR has extensive experience in structural borehole image interpretation to determine the following:
- Density, distribution, and orientation of natural fractures in the reservoir.
- In situ stress orientation—this controls whether fractures are open or closed in the subsurface.
- Structural dip, larger-scale structural zonation, and major faults that may control fracture distribution.
We have worked with both resistivity and acoustic images in lithologies, ranging from carbonates to sandstones to basalt.
Fracture mapping in outcrop analogues
Core and borehole image analysis in 1D cannot directly measure fracture length or connectivity—key controls on fracture permeability. Only 2D outcrop analogue mapping can do this.
RDR has extensive experience in the field mapping of fractures in different lithologies from around the world—both for our consortium research projects and for individual consultancy projects. Outcrop analogue mapping can determine lateral controls on fracture density, determining whether fractures concentrated in the damage zones around larger faults or around fold hinges, as well as whether they are clustered in fracture corridors or form regularly spaced regional fracture sets.
Once the controls on fracture distribution are understood, we can use our proprietary edge detection and curvature analysis algorithms to predict fracture density and distribution in the subsurface based on seismically derived horizon and fault mapping.
Mechanical layering, fracture density, and interlayer connectivity
Mechanical layering is often a key control on fracture density and fracture length. In some cases, the brittle reservoir layers may contain a high density of layer-bound fractures. These cases are likely to have a high horizontal permeability but low vertical permeability, since there is no fracture connectivity between the different brittle layers.
Sometimes, larger fractures develop that cut through the more ductile clay-rich layers to connect adjacent connect brittle reservoir layers. In this case the horizontal permeability is generally lower, since the fracture density is lower, but the vertical permeability is high.
RDR has developed the proprietary Fault Modeler software to predict fracture density and distribution in the subsurface based purely on well log data. This software uses mechanical modeling techniques to achieve the following:
- Calculate key mechanical properties (e.g., UCS, tensile strength, friction coefficient, and crack surface energy) from wireline logs.
- Subdivide the reservoir stratigraphy into mechanical layers.
- Predict which layers will contain layer-bound fractures.
- Predict whether through-cutting fractures will provide vertical connectivity between reservoir layers.
- Predict the density of layer-bound and through-cutting fractures.
Predicting fracture distribution and orientation with geomechanical modeling
Since fractures cannot be imaged directly on seismic data, it is not possible to map their density or orientation away from wellbore control. However, we can use geomechanical modeling to predict fracture density and distribution.
Where fracture distribution is controlled by larger-scale structures, such as faults or folds, 2D or 3D finite element modeling can be used to calculate stress distribution and orientation, and to identify local stress anomalies.
The modeling of outcrop analogues has consistently demonstrated a good agreement between the mapped fracture density and fracture orientation and the calculated stress field around the structure.
These results can be used to help condition DFN models in the subsurface.