--> Saturation Isn’t What it Used to be: Towards More Realistic Petroleum Fluid Saturations and Produced Fluid Compositions in Organic-Rich Unconventional Reservoirs

AAPG ACE 2018

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Saturation Isn’t What it Used to be: Towards More Realistic Petroleum Fluid Saturations and Produced Fluid Compositions in Organic-Rich Unconventional Reservoirs

Abstract

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 King Hubbert in 1953. Likewise, Philippi in 1965 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 asserted saturations are rarely rationalized with capillary pressure data. Water and petroleum yields are inferred from Dean Stark-cleaning – a protocol adopted from organic-poor rocks without modification. Dean-Stark extracts don’t resemble hydrocarbon-rich produced fluids, yet are used to infer saturations without splitting the molecules into those sorbed and immobile during production vs. those in a mobile fluid phase. The industry seems comfortable with the derived low (<50%) Sw! Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don’t produce water. Now, in liquid plays, water cuts are under-appreciated: e.g. 50% in the Eagle Ford and >80% in the Wolfcamp (stock-tank basis). If Sw is so low, where is the water coming from?

Alternately, pyrolysis measures volatile hydrocarbons. Adapting models of organic sorption from the 80’s, we can split total volatiles into sorbed and, by difference, fluid phase yields. Converting to volumes and adding back dissolved gas using an FVF, we can estimate the bulk volume fluid phase - and its saturation, given porosity data. New multi-component pyrolysis tools such as HAWK-PAM may predict compositions of the sorbed and fluid phases. Fluid phase saturations derived from this methodology are directionally lower than those Dean-Stark derived, directionally explaining the water cuts; additionally they may indicate sweet spots in different parts of the rock.

The final piece of the puzzle comes from basin modeling of petroleum charging in the 90’s. Some workers 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 100 nD, both oil and water should flow at Sw > 80%.

Lower petroleum phase saturations and adjusted relative permeability curves better explain observed production behaviors and profoundly alter our view of recovery factors and stimulated rock volume.