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AAPG Bulletin


AAPG Bulletin, V. 106, No. 1 (January 2022), P. 1-20.

Copyright ©2022. The American Association of Petroleum Geologists. All rights reserved.

DOI: 10.1306/07272118227

Impact of natural fractures on production from an unconventional shale: The Delaware Basin Wolfcamp shale

A. C. Salem,1 S. J. Naruk,2 and J. G. Solum3

1Shell International E&P Inc., Houston, Texas; [email protected]
2Earth and Atmospheric Science Department, University of Houston, Houston, Texas; [email protected]
3Shell International E&P Inc., Houston, Texas; [email protected]


This study compares the intensity of natural fractures in whole core to production data from the same intervals in a fine-grained unconventional oil play. The reservoir matrix permeability is ∼4.6 × 10−5 md (4.5 × 10−21 m2), but individual horizontal wells in the play can sustain production rates of 500 to 700 bbl of water and oil per day for years, implying that a combination of induced and natural fractures increases the Previous HiteffectiveTop permeability by one or more orders of magnitude. However, the comparison of the natural fracture intensity with production data shows no correlation between them. After the initial flow-back period, all wells produce oil at similar rates regardless of the intensity of natural fractures. Water production rates from wells with relatively low natural fracture intensity rates are relatively constant (400–600 BWPD), independent of the natural fracture intensity. Water production rates from wells with higher natural fracture intensities range from 490 to 19,600 BWPD, independent of the natural fracture intensities. Therefore, the contributions of natural fractures to flow are interpreted to be negligible compared to the contributions of the induced hydraulic fractures. Detailed quantification of natural fracture intensity and mechanical stratigraphy in such hydraulically fractured reservoirs is interpreted to yield no insight or understanding into hydraulically stimulated well productivity.

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