Turning Rocks Into Oil: Understanding Fluid GOR and API Without Any Fluid

Abstract

From an exploration or development step‐out perspective, Black Oil (GOR ~200 – 1,750) and Volatile Oil (GOR ~ 1,750 – 4,000) are often the more profitable unconventional play objectives. In the past, we have relied primarily on thermal maturation proxies to constrain our fluid windows during basin evaluation when we don’t have fluid information. Because all source rock kerogen conversion kinetics differ to some degree, thermal maturation provides a rough, but useful guide to the type of fluid generated. Ideally, one would like to have fluid PVT data to build an equation of state model, and thus map fluid properties over a frontier basin, but such data only exists in areas that have already been drilled or developed. It is typically not available when exploring frontier or under‐explored basins / sub‐ basins. We have leveraged PVT data collected from numerous unconventional source rock plays and found strong relationships between fluid composition GORsat. Moreover, there are strong relationships between GORsat and saturation pressure, oil viscosity, formation volume factor at Psat, and oil API gravity. Therefore, if one could develop a means of estimating GORsat from source rock, we would be able to estimate fluid composition and develop an analogous equation of state to map fluid properties across unconventional target areas of interest. We report here a means estimating fluid GORsat when we have no fluid, from rocks, via extracted rock pyrolysis gas chromatography. The methodology was validated using both core and cuttings source rock pyrolytic data from the same wells, or from wells adjacent to, the PVT fluid wells in our PVT database. As noted, the PVT database shows strong relationships between GORsat and some compositional ratios. Page 1 of 2 We can use the same compositional ratio data generated from rocks via pyrolysis GC to build a relationship that mimics the PVT database relationship to estimate GORsat without having any fluid. The resulting fluid‐type estimation can be tied to other independent data from rocks alone, such as kerogen kinetic maturation assessments. We will show examples of the technique’s validation and application. The key take‐aways are: 1. We can determine fluid type, without fluid, from solvent extracted source rock 2. This assists us in mapping fluid types where no produced fluid data are available

AAPG Datapages/Search and Discovery Article #90349 © 2019 AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis: Changing of the Guard from Late Mature Experts to Peak Generating Staff, Houston, Texas, March 4-6, 2019