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AAPG Bulletin, V.
Practical approaches to identifying sealed and open fractures Stephen E. Laubach1
Steve Laubach is a senior research scientist at the Bureau of Economic Geology and supervises students in the Department of Geological Sciences at the University of Texas at Austin. He received his B.S. degree in geology from Tufts University and his Ph.D. in structural geology from the University of Illinois. He is an associate editor of the AAPG Bulletin and SPE Reservoir Evaluation & Engineering and is vice chair of AAPG's Research Committee.
Partly supported by United States Department of Energy Contract No. DE-FC26-00BC15308 and by industrial associates of the Fracture Research and Application Consortium: Barrett Resources, BG Group, Chevron USA, Conoco, Devon Energy, Ecopetrol, Enron Global, EOG Resources, Japan National Oil, Lariat Petroleum, Marathon Oil, Pemex Exploracin y Produccin, Petroleos de Venezuela, Petrobras, Repsol-YPF, Schlumberger, Tom Brown, TotalFinaElf, and Williams Exploration & Production. I am grateful to associates for samples used in this study. R. Reed collected scanned CL images and A. Ozkan and A. Makowitz contributed to petrography. L. Bonnell, J. Gale, R. Lander, R. Manceda, R. Marrett, K. Milliken, W. Narr, and J. Olson influenced these concepts. Thanks to R. Nelson, W. DeMis, and an anonymous reviewer for their comments.
For one essential ingredient of permeable fracture networks (degree of fracture pore-space preservation in large fractures), I show how the characterization challenge presented by sparse fracture sampling can be overcome by measuring a surrogate, the abundance of rock-mass cement that precipitated after fractures ceased opening. Sampling limitations are overcome because the surrogate is readily measured in small rock samples, including sidewall cores and cuttings, permitting site-specific diagnosis of the capacity of fractures to transmit fluid over a wider range of sample depths than conventional methods allow. A diverse core database shows that this surrogate correctly predicts where large fractures are sealed. Information on timing of fracture opening relative to cement sequence can be obtained in two ways. First, evidence of fracture-movement history and cement sequences in sparse large fractures can be extrapolated to areas having only cement data. Alternately, evidence of fracture timing can be acquired from sealed, micrometer-scale fractures. Distribution of porosity-reducing cement is commonly heterogeneous (from bed to bed and location to location) in siliciclastic and carbonate rocks. However, because patterns of sealed or open fractures cannot be delineated using fracture observations alone, surrogates have practical value for production fairway mapping and other applications in which identifying open fractures is essential. This study highlights the vital interplay among structural and diagenetic processes for fracture-porosity preservation or destruction.
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