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Ndx Prince

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    minimize the error is to choose a non-parametric variable, the Modal T2time. The mode is robust and does not require the completedistribution to be quantified. When used to estimate permeability, the results exhibit very little scatter throughout the nanoDarcy to

    milliDarcy range and that scatter is symmetrically distributed.

    Once again, the measurement of permeabilities in impermeable samples is oxymoronic, but it will remain an integral facet of the reservoir

    characterization process for tight sands and shales. With the Modal T2method it will be possible to obtain reliable estimates of permeability

    from all available samples, including those that have been compromised due to fracturing. Given the small pore size, it may also be

    possible to extend this technique to particulate samples such as drill cuttings, and extend it to the analysis of NMR logs.

    References

    Chen, S., G. Ostroff, D.T. Georgi, 1998, Improving Estimation of NMR Log T2cutoffValue with Core NMR and Capillary PressureMeasurements, International Symposium of the Society of Core Analysts, The Hague, The Netherlands, September 14-16, paper 9822.

    Shafer, J., S. Chen, D. Georgi, J. Chen, 2005, Methods and Procedures for Calibrating NMR Log Derived Permeabilities, Proceeding of the

    11th

    Annual Formation Evaluation Symposium of Japan.

    Swanson, B.F., 1981, A Simple Correlation Between Permeabilities and Mercury Capillary Pressures, Jour. Pet. Tech., p. 2498.

    Acknowledgements

    The authors would like to thank David Spain and BP Exploration for providing samples and data.

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    NMR T2Spectrum

    0

    5

    10

    15

    20

    0 1 10 100 1000 10000

    T2(msec)

    Porosity(%PV

    Figure 1. Standard interpretation of T2spectra derived from reservoir-quality sandstones.

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    Gas Sand

    0

    0.5

    1

    1.5

    2

    0.1 1 10 100 1000 10000

    T2(msec)

    Porosity(%

    Shale

    0.0

    0.5

    1.0

    1.5

    2.0

    0.1 1 10 100 1000 10000

    T2(msec)

    Porosity(%)

    Figure 2. Representative T2spectra of Tight Sands and Shales. The shale spectrum on the right exhibits subsidiary peaks associated with

    fracture and/or moldic porosity.

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    Mode vs KHg

    R2= 0.9785 R2= 0.9283

    0.0000001

    0.000001

    0.00001

    0.0001

    0.001

    0.01

    0.1

    1

    0.1 1 10 100 1000

    Mode (msec)

    KHg

    (mD)

    Tight Gas

    Shale

    Figure 3. Modal T2 times plotted against Permeability. Most of the tight gas plugs were relatively homogeneous. The two outliers indicated

    on the graph represent heterogeneous plugs containing a significant amount of shale. In both cases the end trim used to determinepermeability was from the sand-rich section of the plug.

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    Mode vs KHg

    R2= 0.9785 R

    2

    = 0.9283

    0.0000001

    0.000001

    0.00001

    0.0001

    0.001

    0.01

    0.1

    1

    0.1 1 10 100 1000

    Mode (msec)

    KHg

    (mD)

    Tight Gas

    Shale

    Coates: Regression-Derived Parameters

    0.0000001

    0.000001

    0.00001

    0.0001

    0.001

    0.01

    0.1

    1

    10

    1E-07 0.000001 0. 00001 0.0001 0. 001 0.01 0.1 1 10

    KHg (mD)

    EstimatedK(mD)

    Tight Gas

    Shale

    Modal Size Method

    0.0000001

    0.000001

    0.00001

    0.0001

    0.001

    0.01

    0.1

    1

    10

    1E -07 0. 000001 0. 00001 0. 0001 0. 001 0. 01 0. 1 1 10

    KHg(mD)

    EstimatedK(mD)

    Tight Gas

    Shale

    Figure 4. A comparison of different permeability estimation methodologies. A)Coates equation with default parameters. B)Coates withRegression-Defined parameters. C)Estimates derived using the Modal T2value.


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