Fractures for Geologists
University of Texas
Date/Time: Tuesday, May 22, 2012 - 11:30am
Location: Telus Convention Centre - Calgary, Alberta
The cut-off date for ticket sales is noon on Thursday, May 17, 2012.
CSPG Member Ticket Price: $42.00 + GST.
NON-MEMBER Ticket PRICE: $45.00 + GST.
Each CSPG Technical Luncheon session is 1 APEGGA PDH Credit.
Natural fracture characterization is an important component of reservoir flow capacity assessment as well as hydraulic fracture propagation analysis. This talk will describe some new developments in understanding natural fracture pattern development and allude to how the difference in natural fracture attributes in sandstones and shales might impact hydrualic fracture operations.
Accurate predictions of natural fracture flow attributes in sandstones and shales require an understanding of the underlying mechanisms responsible for fracture growth and aperture preservation. Geomechanical calculations show that opening mode crack growth (tensile failure) can precede shear failure in the subsurface under a wide range of pore pressure and stress conditions. Crack-seal textures and fracture aperture to length ratios suggest that fractures typically propagate and fill with cement simultaneously. The degree of openness of a fracture to flow depends on the competing rates of mechanical aperture growth and precipitated cement crystal growth. Fractured reservoir permeability is also strongly dependent on fracture pattern geometries. Modeling shows that effective permeabilities calculated for tight gas sandstones depend more strongly on fracture pattern connectivity than on the magnitude of open fracture aperture, in apparent contradiction to the widely applied cubic law for fracture permeability estimation.
Natural fractures in shales seem to have some fundamental differences with sandstones. One aspect commonly observed in shales is a very small fracture spacing to mechanical thickness ratio, often much less than 1. To address this problem, we have developed a coupled poroelastic fracture growth model to investigate the influence of host rock permeability during natural fracture growth. The hypothesis is that for a fracture to develop a substantial stress shadow around it, which would promote wider fracture spacing, it needs to grow faster than its neighbors in order to suppress their growth. Fast fracture growth, however, can be retarded by the lack of fluid replenishment to the fracture in extremely low permeability mudrocks. This allows slower fractures to catch up, and the result should be very close spacing. Preliminary modeling confirms the growth retardation for low permeability rocks, which can change fracture growth time from thousands of years to millions of years.
Dr. Olson joined the faculty of Petroleum Engineering at The University of Texas at Austin in 1995 and holds his Ph.D in Applied Earth Sciences from Stanford University. He has six years of industrial experience at Mobil Oil Corporation and has published many technical articles and reports. He specializes in the applications of rock fracture and continuum mechanics to fractured reservoir characterization, hydraulic fracturing, and rock mechanics. Dr.Olson collaborates with researchers from the Department of Petroleum and Geosystems Engineering, Jackson School of Geosciences and the Bureau of Economic Geology.