Stephen E. Laubach1
Knowledge of where natural fractures are open and capable of conducting fluid can aid exploration and development of many petroleum reservoirs. Yet, this information is usually lacking because conventional analysis of vertical well bores provides only non-systematic and incomplete samples of fracture systems. This inherent sampling challenge can be overcome by unconventional use of readily obtained diagenesis data for one essential ingredient of permeable fracture networks-assessment of the degree of fracture porosity preservation. In sedimentary rocks subject to diagenesis, many microfractures seal shortly after they form, whereas fractures larger than a critical aperture value-the emergent threshold-retain porosity. If these large fractures are sealed, it is by cements that precipitate after fractures cease opening. Fracture size and the rock's diagenetic history govern whether fractures are open or closed. Degradation, the ratio in the rock mass of cement that post-dates fracture opening to available porosity, is an accurate predictor of fracture porosity preservation or destruction. Without recourse to observing large fractures, sealed microfractures below the emergent threshold define time of fracture opening and measurements of post-fracture cement volume in the rock mass are surrogates for the degree of porosity retention in large fractures. Microstructures and authigenic cement are readily measured in small rock samples, including sidewall cores and cuttings, permitting site-specific predictions of fracture porosity preservation that circumvent fracture-sampling limitations. Comparative studies of wells having similar geology and engineering show degradation can correctly predict both fracture attributes and production response.
1Fracture Research and Application Consortium, University of Texas at Austin, Bureau of Economic Geology, Austin, Texas 78712; phone: 512-4716303; e-mail: Steve.Laubach@beg.utexas.edu.