Abstract: Improved quantification of matrix block shape and size for simulation of naturally fractured reservoirs

THOMASEN, J.B., E.J.M. WILLEMSE, C. SONDERSKOV

Fracture density is traditionally measured by counting the number of fractures per foot along hole. This has various disadvantages. First, the resulting apparent density needs to be corrected for the 3-D angle between well-bore and fractures. This correction is cumbersome and unreliable for angles less than 30 degrees. Second, for multiple fracture sets, minor errors in correction factor may result in misjudgment of the relative abundance of one set compared to another. Third, the core or well-bore diameter is neglected. Because a bigger hole intersects more fractures, a large diameter core cannot be compared with a small core, or with logs. For this reason comparisons between wells are not straightforward.

These complications are properly accounted for if the fracture density is measured as fracture surface area per rock volume. The surface area of a fracture within the borehole depends on hole diameter and angle between fracture and well-bore. It can be measured directly or computed in a simple spreadsheet. The interval fracture density is the sum of all fracture surface areas divided by the well or core volume between the interval boundaries. Fractures subparallel to the well form elongate ellipses whereas fractures perpendicular to the well form circles. The latter is the smallest surface area possible and occurs for fractures that have the highest chance of being intersected. Fractures at less than 90 degrees to the hole form ellipses with larger surface area but have less chance of being intersected. This surface area `weighting' eliminates all geometrical complications mentioned above.

To obtain matrix block shape and size, the fracture surface area as a function of 3-D fracture orientation is plotted and contoured in a stereonet. Contour maxima reveal the angle between the matrix block sides, and the magnitude of their surface areas. Based on this, the block shape can be determined. If there are three mutually perpendicular maxima of equal magnitude, for example, a cubic shape is appropriate. Each particular block shape has its characteristic surface area per rock volume. A single cubic block for example, has 6 square sides, giving a characteristic surface area per rock volume of "6a² / a³". The block size "a" can be computed by setting "6a² /a³}" equal to the fracture density measured in the well. Fracture porosity also is easily obtained by multiplying fracture density by a known or assumed fracture aperture. The above method is easy to automate and takes full advantage of all data contained in logs or cores. Field examples show the method to be robust in practice.

AAPG Search and Discovery Article #90942©1997 AAPG International Conference and Exhibition, Vienna, Austria