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The minimum miscibility pressure was determined using empirical correlations as a function of reservoir crude oil composition and its properties.
The well log interpretations include neutron porosity, shale volume, and water saturation, all as a function of reservoir depth.
The problem is thus approached as an inverse problem, in which fracture width is estimated as a function of reservoir production rate.
The model predicts, empirically, the lifetime of a hydrothermal system as a function of reservoir porosity, discharge rate, well spacing, average initial temperature of the reservoir, and injection temperature.
A sensitivity analysis of the most likely shear strength pairs satisfying limit equilibrium was performed as a function of reservoir water condition (i.e., rapid drawdown, dry and wet reservoir condition) and the expected earthquake generated peak horizontal ground acceleration coefficient.
Then, for a given location and time, the reservoir effective permeability is equal to the intrinsic permeability multiplied by the correction factor (Eq. 6) that is a function of reservoir temperature, pore pressure and gas properties including the collision diameter (Eq. 2).
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Effective permeability of any reservoir fluid is a function of the reservoir fluid saturation and the wetting characteristics of the formation.
The first phase involves predicting cumulative hydrocarbon production as a function of declining reservoir pressure.
This chapter describes that predicting cumulative hydrocarbon production is a function of declining reservoir pressure.
It also calls for quantitative estimates of fracture permeability as a function of drawdown (reservoir pressure reduction).
DIN retention in reservoirs (D) within a watershed is estimated as a function of characteristics for each reservoir: mean reservoir depth (m), discharge intercepted by dams (km−3 yr−1), and change in water residence time due to the construction of reservoirs (days).
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