This paper presents the numerical density derivative approach (another phase of numerical well testing) in which each fluid�s\ndensities around the wellbore are measured and used to generate pressure equivalent for each phase using simplified pressure density\ncorrelation, as well as new statistical derivative methods to determine each fluid phase�s permeabilities, and the average\neffective permeability for the system with a new empirical model. Also density related radial flow equations for each fluid phase\nare derived and semilog specialised plot of density versus Horner time is used to estimate k relative to each phase. Results from 2\nexamples of oil and gas condensate reservoirs show that the derivatives of the fluid phase pressure-densities equivalent display the\nsame wellbore and reservoir fingerprint as the conventional bottom-hole pressure BPR method. It also indicates that the average\neffective ????ave ranges between 43 and 57mD for scenarios (a) to (d) in Example 1.0 and 404mD for scenarios (a) to (b) in Example 2.0\nusing the new fluid phase empirical model for????estimation. This is within the ???? value used in the simulation model and likewise that\nestimated from the conventional BPR method. Results also discovered that in all six scenarios investigated, the heavier fluid such as\nwater and the weighted average pressure-density equivalent of all fluid gives exact effective k as the conventional BPR method.This\napproach provides an estimate of the possible fluid phase permeabilities and the % of each phase contribution to flow at a given\npoint. Hence, at several dp???? stabilisation points, the relative ???? can be generated
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