New seismic interpretation methods enhance fracture clarity.

?In the U.S., an estimated 500- to 800 trillion cubic feet of gas in place lie within shale plays. In fact, these shales may be the last big U.S. onshore play and could provide 10% of the nation’s gas by 2015 if identified and recovered.


The Barnett play in northeastern Texas has led the learning curve on how to economically produce gas shales. Individual well production output is modest, but collectively, the thousands of Barnett shale wells have made this the second-largest gas field in the U.S. in just a few years. Not only are Barnett shales from 100 to 1,000 feet thick and organically rich, but they are also brittle and fracture in areas of stress.


New fracture technologies have helped make gas shales more economical. Such technology demonstrates how different geoscience data can be analyzed and interpreted to detect natural fracture systems (NFS). Different techniques are useful to define stress fields, generate fracture-density histograms, and provide actual fracture picks from 3-D seismic and wellbore information. The results from these NFS techniques can be correlated to improve confidence in the fractured reservoir model.


For example, if 3-D seismic has been gathered with azimuthally varying shots and receivers, fractures perpendicular to the azimuth are imaged better, leading to a more accurate estimate of the stress field and direct fracture detection. Multi-azimuth amplitude-versus-offset (AVOZ) analysis takes advantage of all traces in the gather to provide a more accurate estimate and more confidence in the output stress fields than stacked amplitude analysis. While anisotropy also can be influenced by factors that include fluid and lithology changes, these parameters are constant for thick gas-shale reservoirs, and therefore indicative of NFS.


Multi-component surveys, which make use of downgoing P-waves that convert on reflection to upcoming S-waves, are effective for natural fracture detection. Quite often, shear waves are more susceptible to fracture or differential stress than P-waves. Open fractures have a big effect on shear-wave velocities and amplitudes. The NFS-detection workflow first establishes P-wave velocities and Vs-Vp ratios. P and S interval velocities can be determined after pre-stack time migration. Not only can the converted-wave 3-D volume be directly interpreted for fractures, but Vp/Vs and P-S amplitude-ratio analyses can yield direct fault picks as well.


Meanwhile, post-stack techniques can be used on any 3-D seismic volume regardless of its acquisition. Coherence, for example, highlights variations in neighboring waveforms, helping in the detection of faults or stratigraphic discontinuities. Manually interpreting fractures exposed by a coherence cube is tedious and time consuming. Automatic fault extraction (AFE) quickly generates fracture lineaments and connects appropriate lineaments. Two meaningful outputs are generated by this process: direct fracture picks, and rose diagrams of the lineaments that produced the fracture picks.


Because many fractures have little or no throw, their detection is possible by measuring bends in seismic shapes using volume-curvature attributes. Volume curvature can detect tight folds at seismic scale that can indicate subseismic fractures. While the most frequently used volume curvature attributes are most-positive and most-negative, the dip-curvature attribute can often highlight areas where layers are broken and brittle deformation is present. Volume-curvature results are loaded into the AFE process so both actual fracture picks and rose diagram results can be input to the reservoir model.


Each NFS technique yields different types of information. For example, azimuthal velocities and AVOZ indicate the contemporary stress field; whereas coherency, curvature and dilation help the geoscientist describe fracture sets related to the current stress or constraints applied on the field in the past. When well production comes primarily from the in-situ fracture system, these techniques qualitatively help identify zones of higher fracture probability.


Understanding today’s stress field is crucial to optimizing fracture- and front-propagation direction during wellbore stimulation or secondary and tertiary recovery. Quantitative production predictions require modeling and simulation. All of the information is integrated in a geocellular reservoir model with discrete fracture networks to quantify the effect of fractures on reservoir performance. The effective storage and transport characteristics of the fracture networks can be quantified by upscaling fracture porosity and permeability so that the flow can be simulated.


Though fracture detection is not a simple process, flexibility, imagination and a variety of tools and techniques allow even the most complex unconventional reservoirs’ fracture systems to be interpreted and exploited using an integrated geoscience and reservoir modeling workflow.


—Gary Pekarek, geophysical advisor, and Franck Pichard, practice leader, for Integrated Field Studies, Paradigm BV

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