Research on the Correction Method of the Capillary End Effect of the Relative Permeability Curve of the Steady State

Relative permeability curve is a key factor in describing the characteristics of multiphase flow in porous media. The steady-state method is an effective method to measure the relative permeability curve of oil and water. The capillary discontinuity at the end of the samples will cause the capillary end effect. The capillary end effect (CEE) affects the flow and retention of the fluid. If the experimental design and data interpretation fail to eliminate the impact of capillary end effects, the relative permeability curve may be wrong. This paper proposes a new stability factor method, which can quickly and accurately correct the relative permeability measured by the steady-state method. This method requires two steady-state experiments at the same proportion of injected liquid (wetting phase and non-wetting phase), and two groups of flow rates and pressure drop data are obtained. The pressure drop is corrected according to the new relationship between the pressure drop and the core length. This new relationship is summarized as a stability factor. Then the true relative permeability curve that is not affected by the capillary end effect can be obtained. The validity of the proposed method is verified against a wide range of experimental results. The results emphasize that the proposed method is effective, reliable, and accurate. The operation steps of the proposed method are simple and easy to apply.

EVALUATION OF CAPILLARY END EFFECT IN WATER-OIL PERMEABILITY TESTS USING MULTIPLE FLOW RATES TECHNIQUE

Relative permeability curves obtained in laboratory are used in reservoir simulators to predict production and establish the best strategies for an oil field. Therefore, researchers study several procedures to obtain relative permeability curves. Among these procedures are the multiple flow rates injection methods. Thus, this work proposes to develop an experimental procedure with multiple increasing flows. To make this feasible, simulations were initially carried out at CYDAR, aiming to establish flow rates and time necessary to achieve system stabilization, within the limits of the equipment. After that, tests were carried out establishing the minimum time of 5 hours to stabilize the oil production, and the differential pressure at each flow rate. The accounting and minimization of the capillary end effect in these tests were also evaluated. Capillary pressure constraints contributed to minimize the number of possible solutions to the optimization problem improving the fit of solutions for a specific case.

Appearance of Capillary end Effects in Filtration Studies

From theoretical studies and experiments on the core, the so-called capillary end effect, or, as it is also called, the effect of phases capillary entrapment, is known. When carrying out laboratory experiments to determine the relative phase permeabilities, capillary end effects appear on the core models of the reservoir. These effects can occur as a result of capillary ruptures at the ends of the core sample, which leads to the accumulation of one phase in relation to the other, and thereby affects the movement and retention of the fluid. The region of capillary end effect, which occurs due to the rupture of capillaries at the exit from the sample, affects the change in pressure drop and saturation of a particular fluid. If the influence of capillary end effects is significant, then the experimental conditions are modeled incorrectly, which can lead to serious errors in predicting the productivity of the studied formation. This paper presents the results of studying the porosity-permeability properties of determining the relative phase permeabilities and the studies analysis of the capillary end effects influence mechanism on the filtration capacity of rock samples during laboratory studies using the example of terrigenous and carbonate types of the Pavlovskoye reservoir. According to the results of the studies, the significance of capillary end effects in filtration experiments was established using the example of determining the relative phase permeabilities. Recommendations are given with the aim of minimizing the negative influence of end effects. Capillary effects can be overcome by increasing the length of the test sample, as well as by increasing the flow rate of the fluid during a laboratory experiment to determine the relative phase permeabilities.

Evaluation of Relative Permeability Tests One-Step with Bump Flow and Multi-Step

The relative permeability curves obtained in the laboratory are used in reservoir simulators to predict production and decide the best strategies for an oil field. Therefore, researchers are studying several procedures to obtain relative permeability curves, among them the multiple flow rates injection methods. Thus, this work proposes to develop an experimental procedure with multiple increasing flows (multi-step). To make this feasible, simulations were initially carried out at CYDAR, aiming to establish the flow rates and necessary the time to system stabilization, within the limits of the equipment. After that, the tests were carried out and the results obtained were the minimum time of 5 hours to stabilize the oil production and the differential pressure at each flow rate. The accounting and minimization of the capillary end effect in these tests were also evaluated. And the capillary pressure constraints contributed to minimize the number of possible solutions of the optimization problem improving the uniqueness of solution.

Near-Fracture Capillary End Effect on Shale-Gas and Water Production

Summary Capillary end effect (CEE) develops in tight gas and shale formations near hydraulic fractures during flowback of the fracturing-treatment water and extends into the natural-gas-production period. In this study, a new multiphase reservoir-flow-simulation model is used to understand the role the CEE plays on the removal of the water from the formation and on the gas production. The reservoir model has a matrix pore structure mainly consisting of a network of microfractures and cracks under stress. The model simulates high-resolution water/gas flow in this network with a capillary discontinuity at the hydraulic-fracture/matrix interface. The simulation results show that the CEE causes significant formation damage during the production period by holding the water saturation near the fracture at higher levels than that using only the spontaneous imbibition of water. The effect makes water less mobile, or trapped, in the formation during the flowback, and tends to block gas flow during the production. The effect during the production is more important relative to the changing stress. We showed that the CEE cannot be removed completely but can be reduced significantly by controlling the production rate.

Multiphase Flow Under Heterogeneous Wettability Conditions Studied by Special Core Analysis and Pore-Scale Imaging

Summary Wettability is a major factor that influences multiphase flow in porous media. Numerous experimental studies have reported wettability effects on relative permeability. Laboratory determination for the impact of wettability on relative permeability continues to be a challenge because of difficulties with quantifying wettability alteration, correcting for capillary-end effect, and observing pore-scale flow regimes during core-scale experiments. Herein, we studied the impact of wettability alteration on relative permeability by integrating laboratory steady-state experiments with in-situ high-resolution imaging. We characterized wettability alteration at the core scale by conventional laboratory methods and used history matching for relative permeability determination to account for capillary-end effect. We found that because of wettability alteration from water-wet to mixed-wet conditions, oil relative permeability decreased while water relative permeability slightly increased. For the mixed-wet condition, the pore-scale data demonstrated that the interaction of viscous and capillary forces resulted in viscous-dominated flow, whereby nonwetting phase was able to flow through the smaller regions of the pore space. Overall, this study demonstrates how special-core-analysis (SCAL) techniques can be coupled with pore-scale imaging to provide further insights on pore-scale flow regimes during dynamic coreflooding experiments.

A numerical well model considering capillary end effect for the low-permeability gas reservoir

In the recovery of low permeability reservoir, the capillary pressure has an important effect, which may reduce gas production. Due to the capillary end effect, there are two flow patterns in the vicinity of the production well: both water and gas phases can flow into the production well and only gas phase can enter the production well. Based on the analytical equations of one-dimensional radial flow considering the capillary end effect, an alternative numerical well model for low permeability gas reservoir is constructed. Numerical examples show that the proposed model can reflect the dramatic change for saturation and gas-phase pressure in the vicinity of the production well both for two flow patterns, and therefore can predict the gas and water productions accurately at different grid scales. In contrast, the original Peaceman well model for multi-phase flow, which is directly extended from that for single-phase flow, only can provide good prediction under the condition of that the grid size is enough small. Especially, for the original Peaceman well model, this problem is out of control since it is difficult to estimate a suitable grid size.