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References in periodicals archive ?
where [N.sub.o] is the controlled reserves per well, [m.sup.3]; [phi] is the porosity; [S.sub.oi] is the original oil saturation; and [B.sub.oi] is the formation volume factor.
Parameters Value Grid number 100 x 10 x 10 Grid size 1 m x 36[degrees] x 1 m Porosity, % 10.6 Permeability, mD 20 Net pay, m 10 Original pressure, MPa 55 Drainage radius, m 1000 Fluid viscosity, mPa x s 0.4 Formation volume factor 1.6 Original rock compressibility, 8.9 x[10.sup.-3] [MPa.sup.-1] Fluid compressibility, 4.5 x[10.sup.-4] [MPa.sup.-1] Oil recovery rate, % 1 Table 3: Error of the new approach.
Use [[rho].sub.[alpha]0] to represent the conventional formation volume factor, that is [[rho].sub.[alpha]0] = [[rho].sub.[alpha]sc]/[B.sub.[alpha]] (where [[rho].sub.[alpha]sc] is density of [alpha] Phase under standard ground conditions, [B.sub.[alpha]] is the formation volume factor, [alpha] = (g, w)) A length of 1 in Z direction is applied to simplify Eq.
s) 1.47x[10.sup.-5] Density of the gas under standard conditions, 0.425 [[rho].sub.g] (kg/ [m.sup.3]) Density of the water under standard conditions, 0.998 [[rho].sub.w] (kg/ [m.sup.3]) Gas formation volume factor, [B.sub.g] 0.00896 Water formation volume factor, [B.sub.w] 1.0 Initial gas saturation, [S.sub.g] 0.1 Langmiur adsorption constant, [n.sup.[infinity]] 17.63 (m3/t) Langmiur pressure constant, [P.sub.L] (Mpa) 2.2809 Gas solubility in water, [R.sub.sw] 1.3 Gas relative permeability, [K.sub.rg] 7.2% Water relative permeability, [K.sub.rw] 7.2%
Analyzing the Effect of Skin for Varying Permeabilities Upon Flow rate: Considering a reservoir having thickness of 50 ft external and internal radius of 1000 and 0.5 ft respectively formation volume factor of 1.06 and viscosity of 1.03 cp.
It should be noted that some input parameters such as rock compressibility, reservoir pressure, oil formation volume factor ([B.sub.o]), water formation volume factor ([B.sub.w]), etc.
The data include trap style, depth to crest, lowest closing contour, OWC or GWC, hydrocarbon column height, pay formation, age, thicknesses, porosity, permeablity, petroleum saturation, oil and gas densities, viscosities and bubble points, gas/oil ratio, formation volume factor, water salinity and resistivity, reservoir pressure and temperature, field area, rock volume, oil/gas in place, recovery factor, start up date, production rates and number of wells.
Curve (1) is the crude oil viscosity curve, curve (2) is the oil volume factor curve; curve (3) is solution gas-oil ratio curve; curve (4) is gas formation volume factor curve; curve (5) is gas viscosity curve.
From a review of literature survey of various authors (Standing, 1962, Glaso, 1980, Al-Marhoun, 1988, Labedi, 1990, Al-Shammasi, 2001, etc.), it is observed that the best suited correlation for oil formation volume factor, Bo, is that of A.A.
The objective of the present study is to develop a suitable correlation for predicting oil formation volume factor (Bo) as a function of solution gas oil ratio, stock tank oil relative density, reservoir temperature based on laboratory analyzed PVT data collected from different wells for parts of oil fields of Upper Assam Basin (Figure-1).
Methodology: (For Development of oil formation volume factor, ([B.sub.o]) Correlation):
PVT properties include determination of saturation pressures, compositional characterizations, formation volume factors, viscosities, and gas-to-oil ratios.
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