Broken N Blog

“Creating a Static Conceptual Fracture Model for Reservoir Simulation, Part 2”

In this my second in a sequential blog on creating Quality Static Conceptual Fracture Models, I focus on continuation of the first 4 elements that are the more standard ones included in most models, that being fracture fill and fracture morphology, Table 1. 



  1. Fracture Origin

  2. Fracture Orientation(s) & its’ distribution

  3. Fracture Spacing & its’ distribution

  4. Fracture Morphology/Fill

  5. Selection of static conceptual fracture modeling style

  6. Fracture Aperture

  7. In situ Stress Component magnitude & direction

  8. Fracture Scaling

  9. Predictions of properties away from control, including mechanical fracture predictions in 3D & competing mechanisms

  10. Calibration to production, testing and water-cut

  11. Flow Exchange (Cross Flow, Sigma Factor, Transmissibility)

  12. Relation between fracture distribution and flow/permeability


Table 1.  The list of key elements included in a quantified complete Static Conceptual Fracture Model.


 


There are a couple approaches to defining fracture filling and morphology, both allow for the predictability of flow potential of the fracture system vertically and laterally in the reseroir.  The first is difined by direct rock observation in outcrop or core, Figure 5.  The classification is based on degree of both mineralization in the fractures or deformation along the fractures, Figure 5.  Examples of various of these fractrure morphologies in core and outcrop photos is shown in Figure 6.



Figure 5.  Fracture Morphology Types derived from direct observation of fractures in outcrop and core as defined in Nelson (1985).




Figure 6.  Core and outcrop examples of the fracture morphologies defined in Figure 5.  These various morphologies are shown to be very important in defining the flow capabilities of the fractures in the subsurface in Nelson (1985 & 2001).


However, much of our subsurface fracture data today comes from Borehole Image Logs.  The second approach defines how filled the fractures are.  In either the ultrasonic or resistivity image logs the output of fracture type is primarily in the form of fracture filling (closed, open, or partially open).  It is often difficult to tell what type of filling actually exists ; deformation or mineralization.  As a result, we open map the fracture filling as the percentage of open + partially open fractures interpreted within the well as interpreted in the image log.  Figure 7 shows an example of a map of open fractures in a field area.



 


Figure 7.  An example of a map of the % of Open  + Partially Open Fractures within a field area as interpreted in borehole image logs.


As with the fracture intensity displays in blog installment 1 last month, fracture fill data can be displayed in histogram format for a better visual feeling on relative distribution from one well to another, Figure 8.  These data can also be displayed for each mechanical and diagenetic unit within the reservoir in map or histogram form as displayed here, or displayed along wellbores as companion fracture intensity curves for both all interpreted fractures and just open and partially open fractures.




Figure 8.  An example of histogram display of the % cemented fractures (no flow) which is the inverse of open and partially open fractures.  This display shows the difference in fracture flow capability from well to well.  This display is from the same general area shown in Figure 7.


However, this data is intended to be used to constrain reservoir simulation models.  Therefore, the simulation engineers often require a measure of flow uncertainty associated with the fractures within the reservoir.  As a result, the data is often turned into a flow capability uncertainty diagram such as shown in Figure 9.




Figure 9.  Shown is an example of a fracture filling display used to suport flow simulation modeling.  The filling data is turned into a % of fractures per unit on average that will flow, that will not flow, and that we are uncertain as to whether they will or will not flow in the subsurface.  This allows for multiple runs spanning the range of uncertainty of this parameter.


In next months blog,  I will address the element of selection of the Static Fracture Modeling Style.


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