March 9, 2021


Description

Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert. Likewise, Philippi noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don’t produce water. So, in more liquid-rich plays, water cuts were initially underappreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production?

 

Adapting organic sorption models from the 80’s, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations.

 

The final piece of the puzzle comes from basin modeling of petroleum charging in the 90’s. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw >80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume.

 


Featured Speakers

Speaker Andrew Pepper

This year Andy Pepper will celebrate 40 years experience' as a geologist and petroleum systems analyst: at BP as leader of the Petroleum Systems Network; at Hess as Chief Geologist and then Director of New Ventures; and at BHP as VP Geoscience and VP Unconventional Exploration. He founded This is …

This year Andy Pepper will celebrate 40 years experience' as a geologist and petroleum systems analyst: at BP as leader of the Petroleum Systems Network; at Hess as Chief Geologist and then Director of New Ventures; and at BHP as VP Geoscience and VP Unconventional Exploration. He founded This is Petroleum Systems LLC in 2015 as a vehicle to collaborate and innovate in Petroleum Systems concepts, modeling and training. Since 2015 Andy has been working on techniques to improve estimation of Shale water saturation, which is the foundation of today’s talk.

Full Description



Organizer

David Traugott

david.traugott@nov.com ;  936-777-6204


Date and Time

Tue, March 9, 2021

noon - 1 p.m.
(GMT-0500) US/Central

Event has ended

Location

Webinar - Online or Phone



"Log in" and "phone-in" info for the webinar will be emailed to the participants prior to the event.

Group(s): Northside