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Derivation of Hydrocarbon Head Potential, a New Workflow for Petroleum System Analysis: Application to the Eagle Ford Formation, SE Texas


Hydrocarbon charge assessment in hybrid systems has presented challenges for petroleum system analysis and modeling the resource potential still retained within self-sourced and near-sourced tight liquids. In tight liquids, regional trends of key controlling properties such as pressure regimes, fluid phase, density, and maturity, and geomechanics result in preferential “sweet spots” where well performance far exceeds the formation mean. We built and calibrated a basin model for the Eagle Ford Formation, to match retained fluid properties and volumes. We present a new workflow for estimating Hydrocarbon Head Potential (HCHP), a function of fluid pressure, density, Gas Oil Ratio (GOR) and source rock and fluid maturity that has a direct correlation with well performance and our understanding of seal capacity and pressure evolution in the subsurface. Well performance is here defined as the initial best month rate of production, normalized by lateral wellbore length and barrels of oil equivalent (BOE) per day. HCHP is a property derived through basin modeling and calibrated to the observations at the wellhead in terms of produced fluid volumes, density and GOR. This study shows that pressure and fluid properties are main drivers behind well performance in tight liquid systems. For this study, well performance (BOE/d), GOR and density of the fluid were evaluated for 12,000 wells producing from the Eagle Ford Fm. Average rock properties obtained for 8,000 locations, including total organic carbon content, clay volume, hydrocarbon pore volume, and net thickness, were used as inputs in the basin model. The basin model estimated hydrocarbon fluid density and gas oil ratio of both the retained and expelled fluid volumes from the source rock, and its associated rock and fluid maturities. We developed a GOR-fluid density function by modelling recombined fluids from 18 PVT reports. Statistical analysis via principal component analysis and clustering techniques supports that fluid properties and pressures have a strong correlation to BOE recovered in the first three months of production. Results show that HCHP can predict the volume and initial production rate of hydrocarbons in the subsurface, and be used as a surrogate for fluid pressure. Integration of the HCHP property into the basin modeling workflow may provide insights into seal capacity, fluid maturity trends, and the impact of multiple charge events on bulk fluid properties.