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Abstract
In oil reservoir, the pressure energy is declined due to
production of reservoir fluids. Waters from sea or water – wells are
usually injected into reservoirs to conserve this energy. Mixing of
injected water with that existed in the reservoir (formation water)
results in scale deposits which lead to plugging of porous media
around well-bore in injection wells.
Regarding the cost of drilling injection wells (5 million
dollars / onshore and 20 million dollars / offshore well), we have to
prevent or minimize the scale deposits in porous media. This
problem can be bridged by using scale inhibitor. Therefore, the
main objectives of this study is to first evaluate scale tendency in
the porous media resulting from mixing of two incompatible waters
and, second to evaluate scale tendency after adding proper scale
inhibitor to the injection waters.
In this study, experimental work and ScaleChem software
was used to evaluate the scaling tendency of the commingling of
two incompatible waters for Egyptian oil reservoirs existed in Gulf of Suez area. The chemical analyses of the two incompatible waters
(injection and formation waters) have been used as input data to the
computer simulator. The reservoirs characterized by a temperature
range of 90-127oC, and salinity of 100,000-230,000 ppm. The
scaling results for the commingling of both injection and formation
water at reservoir temperatures and pressures were determined
from experimental work and software. Results showed that mixing
of injection water (60%) and formation water (40%) leads to
deposits with considerable amounts of calcium carbonate and
barium sulfate scales in absence of scale inhibitor. Adding scale
inhibitors to the injection water reduces the porous media plugging
by 21.325 to 29.2 %. The proper scale inhibitor for the studied
reservoir was AII which has an efficiency of 67.09 and 78.012 %
for formation type A and B, respectively.
Keywords: Scale inhibitor, scale deposition; scale prediction; and
soft ware simulator.