Natural Fractures on the Pinedale Anticline as Seen in Cores and on Image Logs
Published:January 01, 2014
Mark Longman, Erika Davis, Randy J. Koepsell, 2014. "Natural Fractures on the Pinedale Anticline as Seen in Cores and on Image Logs", Pinedale Field: Case Study of a Giant Tight Gas Sandstone Reservoir, Mark W. Longman, Stephen R. Kneller, Thomas S. Meyer, Mark A. Chapin
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Open natural fractures commonly influence the production of natural gas by increasing permeability. To assess the abundance and orientation of natural fractures along the northern third of the Pinedale anticline, a suite of 14 cores totaling 1300 ft (400 m) in length from eight wells and 13,894 ft (4235 m) of image log data run over the upper 1300 to 4300 ft (400–1300 m) of the 6000-ft (1800 m) thick gas-bearing Lance Pool in four vertical wells were studied. Formation MicroImager™ (FMI) logs capable of distinguishing between open (conductive) and cemented (resistive) fractures were run in these four wells, all drilled with water-based mud, between 2000 and 2002 and reinterpreted as a group in 2010 for consistency. These image logs reveal that the total number of fractures per well ranged from 38 directly on the crest of the anticline to 74 a mile and a half (2.4 km) down the east flank of the anticline. Normalized values for the number of natural fractures, both open and healed, per 1000 vertical feet (300 m) of section ranged from 9.2 to 29.5 along the crest of the anticline with the eastern flank well having 17.1 fractures per 1000 ft (300 m) of image log data. For comparison, image logs run through the gas-productive Upper Cretaceous Mesaverde Group in the Piceance Basin average 42 natural fractures per 1000 ft (300 m) of section.
In the wells on the crest of the Pinedale anticline, open and healed fractures occur in approximately equal numbers, but the northernmost study well on the north plunge of the anticline had 75% healed fractures whereas the eastern flank well had 58% open natural fractures. The dominant orientation of both the open and healed fractures is N60°W, which is oblique to the N15°W orientation of the northern axis of the Pinedale anticline. Based on both drilling induced shear fractures and borehole breakout patterns, Sigma 1 (σ1), the direction of maximum principal stress along which artificially induced fractures are likely to trend, ranges from N26°W to N30°W about 30° off the trend of the sparse natural fractures with the northernmost study well on the north plunge of the anticline a bit less askew at N38°W.
Image logs run in underbalanced wells show good to excellent gas entry into the well bore from sandstones but only minor or no entry from the natural fractures. However, comparing cumulative gas production for the first 21 months of each study well with the normalized number of total fractures determined from FMI logs revealed a strongly positive correlation (R2 = 0.958) between the abundance of fractures and production. The two least fractured wells with less than 10 fractures per 1000 ft (300 m) of logged interval each yielded less than 1 BCF in their first 21 months of production whereas a well with almost 30 fractures per 1000 ft (300 m) of logged interval produced 2.2 BCF of gas. A highly fractured well at the south end of the Pinedale anticline, the Antelope 15-4, which had an image log showing 71 fractures per 1000 ft (300 m), produced 5.165 BCF in its first 21 months of production.
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Pinedale Field: Case Study of a Giant Tight Gas Sandstone Reservoir
Improved geologic insights combined with advances in technology and innovative thinking, mainly since the laste 1990s, have driven Pinedale field’s development and unlocked a giant natural gas resource in stacked low-permeability fluvial sandstones. Understanding this field can provide a model for developing similar tight sandstone reservoirs around the world. This memoir contains 15 well-illustrated, peer reviewed chapters that describe the history of field development, the deposition and diagenesis of the reservoir rocks, geophysical characteristics of the field, special core analysis techniques used to better quantify the reservoir, petrophysical characteristics and interpretations of the reservoir, the types and abundance of natural fractures, and fluid production characteristics in the field. Finally, static and dynamic models for the field are presented in an attempt to integrate all the pieces of this giant geologic puzzle.