Bridging the ‘Gap’ to Unconventional Permeabilitys: Insights to Unconventional Tight Oil Techniques, Advancements and Understandings

Abstract

The ground-breaking development and application of the crushed rock permeability technique (Luffel et al., 1992) to address the nanodarcy (~10e-9) scale flow capacity present in unconventional source- now reservoir rocks allowed the industry to quantify the storage and flow capacity of shale oil and gas volumes. The methodology of the technique, while constrained, resulted in various laboratories internally standardizing the mathematical algorithms for the pressure-decay time function to then report quantified ‘crushed rock permeability’ resulting in known 1-to 2x order of magnitude difference in measured and reported flow capacity (lab-dependent). A case study presented here demonstrates the inter-lab discrepancy as measured on identical homogenized samples from an unconventional, thinly-bedded reservoir with inter-bedded, organic-rich (>2 wt%) self-sourcing layers. Further, the case study presents a plausible solution to correct for inter-lab discrepancy in measured and reported crushed rock permeability. Second, the case study presents an example where mass limited analytical measurements can be obtained and mathematical algorithms adjusted to report accurate crushed rock permeability with samples that are approximately less than 30-50 grams in weight. The advancement allows for the application of crushed rock permeability's to be measured on significantly less acquired material, an important financial impact in application of the technique as often oil and gas companies are limited in physical acquisition of rock volume available for analytical quantification. Lastly, we address the known issue in using discretely various methodology (ex. CMS 300 Tight Permeability Technique, Probe Permeability and Crushed Rock Techniques) with overlapping reportable analytical scales in the quantification of absolute permeability resulting in petrophysical challenges for integration and up-scaling. Three applied solutions and the variability/uncertainty they invoke in terms of quantification are presented as observational evidence and justification for multi-scale modelling to be applied in heterogeneous source-to reservoir rock tight oil plays. Examples of direct impact and along wellbore magnitude of change in absolute permeability are provided to constrain the prediction of fluids (hydrocarbon and water) in an along wellbore profile.

AAPG Datapages/Search and Discovery Article #90291 ©2017 AAPG Annual Convention and Exhibition, Houston, Texas, April 2-5, 2017