Abstract
Abstract
The effect of flow rate on relative permeability curves has been investigated in very tight Iranian carbonate rocks. Core samples were prepared from outcrop of Asmari formation. Asmari formation represents huge oil carbonate reservoirs in Iran. This formation belongs to Oligocene-Miocene period and is mainly limestone. The dynamic displacement experiments were performed at three different flow rates. In all experiments, we injected both water to displace oil and oil to displace water and relative permeability curves were generated with the Jones and Roszelle method for both water-flooding and oil-flooding experiments.
We found a critical rate in which we could not obtain any relative permeability curves above this rate. This critical rate represents the limit of injectivity capacity of each core sample.
We observed that in the water-flooding process, water relative permeability curves and its end points were not affected by flow rate. However, it was detected that the oil relative permeability decreases at lower flow rates. This variation vanishes at the central saturation points. During oil-flooding experiments, we also observed the same no rate effect in water relative permeability curve but in the oil relative permeability curves, although it was seen the flow rate effect, it was not found any meaningful trend in the curves and its end-point saturations.
We found hysteresis effect in both water and oil relative permeability curves. At higher flow rates, the effect of this phenomenon increases in water relative permeability curves while the hysteresis effect decreases in the oil relative permeability curves.
Introduction
One of the most useful concepts in describing the flow of multiphase system is relative permeability. In general, methods for measuring relative permeability consist of laboratory and non-laboratory methods. Since relative permeability is depend upon both the fluid saturation and the distribution of the fluids in the interstices of the porous media, therefore various laboratory methods are arisen to different results.
The experimental relative permeability values for a given rock-fluid system can be determined by one of two common laboratory methods: steady-state and unsteady-state techniques. In the steady-state methods, two or three fluids are injected simultaneously at constant rates or pressure for extended durations to reach equilibrium. The saturation, flow rates and pressure gradients are measured and used in Darcy's law to obtain the effective permeability for each phase while, in unsteady-state method, saturation equilibrium is not attained; thus, an entire set of relative permeability vs. saturation curves can be obtained in a few hours. On of the main disadvantage of these methods is the inability to determine relative permeability for a wide range of saturation level.
In order to study the effect of rate on relative permeability measurement, generally, it is believed that "end effect" is the main reason for that the changes in relative permeability with different rates. End effect or boundary effect refers to a discontinuity in the capillary properties of a system at the time of relative permeability measurement. In a stratum of permeable rock, the capillary forces act uniformly in all direction and thus negate each other. In a laboratory sample, however, there is a saturation discontinuity at the end of a sample. When the flowing phases are discharged into an open region under atmospheric pressure, a net capillary force persists in the sample; this force tends to prevent the wetting phase from leaving the sample. The accumulation of the wetting phase at the outflow face of the sample creates a saturation gradient along the sample which disturbs the relative permeability measurement.
Owens et al.1, Sandberg et al.2, Kyte and Rappoport3, and Perkins4 believe that the most convenient way of minimizing the boundary effect is the adjustment of capillary forces to insignificant values, as compared to the viscous forces. This is usually done by a flow rate adjustment.
Experimental results by Richardson et al.5 demonstrated that, for two-phase flow in a core, a relatively uniform saturation distribution was obtained toward the inflow end. However, a zone of increasing wetting-phase saturation existed toward the outflow end with the maximum saturation value occurring at the effluent face. The width of the zone decreased with increased flow rate. It appears that a very high flow rate may be required to remove the zone effectively in every case.