Abstract: Recently increasing oil production from petroleum reservoirs is one of the most important issues in the global energy sector. So, in this paper, the recovery of oil by the waterflooding technique from petroleum reservoir are considered. To investigate the aforementioned phenomena, the relative permeability of two immiscible fluids in sand is measured in the laboratory based on the steady-state method. Two sorts of oils, kerosene and heavy oil, and water are pumped simultaneously into a vertical sand column with different pumping ratio. From the change in fractional discharge measured at the outlet, a method for determining the relative permeability is developed focusing on the displacement mechanism in sand. Then, displacement mechanism of two immiscible fluids in the sand is investigated under the Buckley-Leveret frontal displacement theory and laboratory experiment. Two sorts of experiments, one is the displacement of pore water by oil, the other is the displacement of pore oil by water, are carried out. It is revealed that the relative permeability curves display tolerably different shape owing to the properties of oils, and produce different amount of residual oils and irreducible water saturation.
Abstract: This paper evaluates oil displacement by water in Hauterivian sandstone reservoir of Kashkari oil field in North of Afghanistan. The core samples of this oil field were taken out from well No-21st, and the relative permeability and fractional flow are analyzed. Steady state flow laboratory experiments are performed to empirically obtain the fractional flow curves and relative permeability in different water saturation ratio. The relative permeability represents the simultaneous flow behavior in the reservoir. The fractional flow approach describes the individual phases as fractional of the total flow. The fractional flow curve interprets oil displacement by water, and from the tangent of fractional flow curve can find out the average saturation behind the water front flow saturation. Therefore, relative permeability and fractional flow curves are suitable for describing the displacement of oil by water in a petroleum reservoir. The effects of irreducible water saturation, residual oil saturation on the displaceable amount of oil are investigated through Buckley-Leveret analysis.
Abstract: This paper evaluates and compares the effect of fractional flow curves on the heavy oil and light oil recoveries in a petroleum reservoir. Fingering of flowing water is one of the serious problems of the oil displacement by water and another problem is the estimation of the amount of recover oil from a petroleum reservoir. To address these problems, the fractional flow of heavy oil and light oil are investigated. The fractional flow approach treats the multi-phases flow rate as a total mixed fluid and then describes the individual phases as fractional of the total flow. Laboratory experiments are implemented for two different types of oils, heavy oil, and light oil, to experimentally obtain relative permeability and fractional flow curves. Application of the light oil fractional curve, which exhibits a regular S-shape, to the water flooding method showed that a large amount of mobile oil in the reservoir is displaced by water injection. In contrast, the fractional flow curve of heavy oil does not display an S-shape because of its high viscosity. Although the advance of the injected waterfront is faster than in light oil reservoirs, a significant amount of mobile oil remains behind the waterfront.
Abstract: Relative permeabilities are practical factors that are used to correct the single phase Darcy’s law for application to multiphase flow. For effective characterisation of large-scale multiphase flow in hydrocarbon recovery, relative permeability and capillary pressures are used. These parameters are acquired via special core flooding experiments. Special core analysis (SCAL) module of reservoir simulation is applied by engineers for the evaluation of these parameters. But, core flooding experiments in shale core sample are expensive and time consuming before various flow assumptions are achieved for instance Darcy’s law. This makes it imperative for the application of coreflooding simulations in which various analysis of relative permeabilities and capillary pressures of multiphase flow can be carried out efficiently and effectively at a relative pace. This paper presents a Sendra software simulation of core flooding to achieve to relative permeabilities and capillary pressures using different correlations. The approach used in this study was three steps. The first step, the basic petrophysical parameters of Marcellus shale sample such as porosity was determined using laboratory techniques. Secondly, core flooding was simulated for particular scenario of injection using different correlations. And thirdly the best fit correlations for the estimation of relative permeability and capillary pressure was obtained. This research approach saves cost and time and very reliable in the computation of relative permeability and capillary pressures at steady or unsteady state, drainage or imbibition processes in oil and gas industry when compared to other methods.
Abstract: To derive the fractional flow equation oil
displacement will be assumed to take place under the so-called
diffusive flow condition. The constraints are that fluid saturations at
any point in the linear displacement path are uniformly distributed
with respect to thickness; this allows the displacement to be described
mathematically in one dimension. The simultaneous flow of oil and
water can be modeled using thickness averaged relative permeability,
along the centerline of the reservoir. The condition for fluid potential
equilibrium is simply that of hydrostatic equilibrium for which the
saturation distribution can be determined as a function of capillary
pressure and therefore, height. That is the fluids are distributed in
accordance with capillary-gravity equilibrium.
This paper focused on the fraction flow of water versus
cumulative oil recoveries using Buckley Leverett method. Several
field cases have been developed to aid in analysis. Producing watercut
(at surface conditions) will be compared with the cumulative oil
recovery at breakthrough for the flowing fluid.
Abstract: Considering the numerous applications of the study of
the flow due to leakage in a buried pipe
in unsaturated porous media, finding a proper model to explain the
influence of the effective factors is of great importance.There are
various important factors involved in this type of flow such as: pipe
leakage size and location, burial depth, the degree of the saturation of
the surrounding porous medium, characteristics of the porous
medium, fluid type and pressure of the upstream.In this study, the
flow through unsaturated porous media due to leakage of a buried
pipe for up and down leakage location is studied experimentally and
numerically and their results are compared. Study results show that
Darcy equation together with BCM method (for calculating the
relative permeability) have suitable ability for predicting the flow due
to leakage of buried pipes in unsaturated porous media.
Abstract: When acid is pumped into damaged reservoirs for
damage removal/stimulation, distorted inflow of acid into the
formation occurs caused by acid preferentially traveling into highly
permeable regions over low permeable regions, or (in general) into
the path of least resistance. This can lead to poor zonal coverage and
hence warrants diversion to carry out an effective placement of acid.
Diversion is desirably a reversible technique of temporarily reducing
the permeability of high perm zones, thereby forcing the acid into
lower perm zones.
The uniqueness of each reservoir can pose several challenges to
engineers attempting to devise optimum and effective diversion
strategies. Diversion techniques include mechanical placement and/or
chemical diversion of treatment fluids, further sub-classified into ball
sealers, bridge plugs, packers, particulate diverters, viscous gels,
crosslinked gels, relative permeability modifiers (RPMs), foams,
and/or the use of placement techniques, such as coiled tubing (CT)
and the maximum pressure difference and injection rate (MAPDIR)
It is not always realized that the effectiveness of diverters greatly
depends on reservoir properties, such as formation type, temperature,
reservoir permeability, heterogeneity, and physical well
characteristics (e.g., completion type, well deviation, length of
treatment interval, multiple intervals, etc.). This paper reviews the
mechanisms by which each variety of diverter functions and
discusses the effect of various reservoir properties on the efficiency
of diversion techniques. Guidelines are recommended to help
enhance productivity from zones of interest by choosing the best
methods of diversion while pumping an optimized amount of
treatment fluid. The success of an overall acid treatment often
depends on the effectiveness of the diverting agents.
Abstract: Gas condensate Reservoirs show complicated thermodynamic behavior when their pressure reduces to under dew point pressure. Condensate blockage around the producing well cause significant reduction of production rate as well bottom-hole pressure drops below saturation pressure. The main objective of this work was to examine the well test analysis of naturally fractured lean gas condensate reservoir and investigate the effect of condensate formed around the well-bore on behavior of single phase pseudo pressure and its derivative curves. In this work a naturally fractured lean gas condensate reservoir is simulated with compositional simulator. Different sensitivity analysis done on Corry parameters and result of simulator is feed to analytical well testing software. For consideration of these phenomena eighteen compositional models with Capillary number effect are constructed. Matrix relative permeability obeys Corry relative permeability and relative permeability in fracture is linear. Well testing behavior of these models are studied and interpreted. Results show different sensitivity analysis on relative permeability of matrix does not have strong effect on well testing behavior even most part of the matrix around the well is occupied with condensate.