Chemical inputs into oil basin modeling
Peter MeuLBroek, MSC
Sedimentary basins represent an exciting new area of application for modeling techniques developed and applied at the MSC. The MSC has recently been funded by the Department of Energy, in conjunction with Cornell University and GeoGroup, Inc., to develop a public domain two-dimensional basin model. Basin modeling attempts to reconstruct the thermal, pressure, fluid-flow, and fluid compositional history of a sedimentary basin using a combination of seismic and oil-well data. The models are utilized in a variety of academic and industrial settings, most notably in hydrocarbon exploration and exploitation.
The current state-of-the-art in basin modeling involves two-dimensional modeling of the physical state of the basin. Modeled parameters include temperature history, tectonic history, and sedimentation history. Less well-developed are models of pressure history, salt and shale redistribution, and fluid chemistry. The MSC contribution to the modeling project has particular emphasis on the modeling of hydrocarbon fluid chemistry through a variety of pressure and temperature regimes, and as thermal stress causes a breakdown of oil components to more stable products. An accurate modeling of the chemistry of hydrocarbon fluids can act as an important calibration parameter for the basin model. Furthermore, since the chemistry and phase state of hydrocarbons can have an impact on the economics of hydrocarbon production, accurate modeling of hydrocarbon chemistry can aid in risk management and exploration decision-making.
My current work at the MSC is aimed at developing and deploying tools to model the chemistry of hydrocarbon fluids. In engineering fluid flow problems such as reservoir management, the accepted toolkit includes equations of state and fluid phase equilibria models. These tools require some modification before they can be deployed in a basin model, as the problem constraints are somewhat different than those faced by the petroleum or refinery engineer. Most notably, the pressure-temperature conditions deep within a basin are quite different than those of the hydrocarbon reservoir, and the flow system is open, rather than closed. My current work includes deployment of new equations of state, implementation of lumping schemes to divide an oil of uncertain composition into manageable fractions, and porting these models to the Windows NT environment. Future applications of the work can be expected in both upstream (exploration and exploitation) and downstream (refinery) problems. With some adaptation, these models can address more surficial problems such as multiphase pollution flow in groundwater.
Support for this project is gratefully acknowledged from the Department of Energy National Petroleum Technology Fund.