Effect of Flow Rate on Imbibition Three-Phase Relative Permeabilities and Capillary Pressures

1997 ◽  
Author(s):  
Serhat Akin ◽  
M.R. Birol Demiral
Keyword(s):  
Flow Rate ◽  
Relative Permeabilities ◽  
Three Phase ◽  
Capillary Pressures

A Numerical Model of Multiphase Flow Around a Well

1973 ◽  
Vol 13 (06) ◽  
pp. 311-320 ◽  
Author(s):  
F. Sonier ◽  
O. Ombret
Keyword(s):  
Numerical Model ◽  
Flow Rate ◽  
Two Dimensional ◽  
Simultaneous Solution ◽  
Relative Permeabilities ◽  
Time Step ◽  
Flow Rates ◽  
Fully Implicit ◽  
Three Phase ◽  
Potential Methods

Abstract This paper describes a two-dimensional three-phase numerical model for simulating two- or three-phase coning behavior. The model is fully implicit with respect to all variables and uses the simultaneous solution of the different equations describing multiphase flow. For determining well flow rates from all blocks communicating with the well, particular attention has been paid to the well boundary condition, which is considered to be a physical boundary. The mathematical expression of these well conditions enables flow rates to be calculated in a perfectly implicit manner and thus makes the model very stable so that the computational error in time is very small. The model described is appreciably different in this respect from previous models in which the well is represented by source points and in which the flour terms are calculated by using various simplifications. The results of several tests are presented. The model was checked by the simulation of several water coning cases that had previously been studied on a physical model. Four examples are given here. In these examples, the boundary influx conditions and fluid mobility ratio are made to vary. One of them illustrates the care that must be taken when using simplified solution schemes for the boundary conditions. Introduction Multiphase numerical models have usually employed finite-difference approximations in which relative permeabilities are evaluated explicitly at the beginning of each time step. But simulators of this type are not capable of solving problems characterized by high flow velocities and such phenomena as well coning, except perhaps at phenomena as well coning, except perhaps at extremely high cost. Recently, some papers were published describing a method that employs semi-implicit relative permeabilities and uses the simultaneous solution of multiphase equations. This method is very efficient. In these simulators, the well is represented by source points, and flow rate terms are calculated by using various simplifications (mobility or potential methods). potential methods). This paper describes a new numerical coning model. The numerical part of the model is similar to that in the latest models, but its representation of wellbore conditions is quite different and more nearly expresses physical phenomena caused by end effects. The well is represented full-scale and not by source points. Furthermore, so as not to partially screen out wellbore conditions, the partially screen out wellbore conditions, the producing interval, even if it is small, may be producing interval, even if it is small, may be advantageously represented by several layers. Any condition may be specified for the external boundaries. All the leading physical parameters are treated semi-implicitly. When a flow rate is imposed on the well, taking into account the well-wall boundary conditions, the calculation of production terms is fully implicit. This calculation is iterative, but at almost each time step a simple algorithm enables a direct solution to be obtained. The results of numerous simulations are presented. Studies on physical models have demonstrated the full validity of the numerical model. The simulation of actual field cases shows that the model is very efficient. CONING MODEL The numerical model described in this paper is a two-dimensional one with radial symmetry. A compressible three-phase system is considered, with possible exchange between the gas and oil phases independently of the composition. phases independently of the composition. The introduction of Darcy's law into the continuity equation for each of the three fluids leads to a system of partial differential equations. SPEJ p. 311

A New Way of Compositional Simulation without Phase Labeling

SPE Journal ◽  
2021 ◽  
Vol 26 (02) ◽  
pp. 940-958
Author(s):  
Saeid Khorsandi ◽  
Liwei Li ◽  
Russell T. Johns
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Computational Time ◽  
Relative Permeabilities ◽  
Compositional Simulation ◽  
Three Phase ◽  
Compositional Simulator ◽  
Capillary Pressures ◽  
Compositional Variations

Summary Current relative permeability models rely on labeling a phase as “oil” and “gas” and cannot therefore capture accurately the effect of compositional variations on relative permeabilities and capillary pressures in enhanced oil recovery processes. Discontinuities in flux calculations caused by phase labeling problems not only cause serious convergence and stability problems but also affect the estimated recovery factor owing to incorrect phase mobilities. We developed a fully compositional simulation model using an equation of state (EoS) for relative permeabilities (kr) to eliminate the unphysical discontinuities in flux functions caused by phase labeling issues. The model can capture complex compositional and hysteresis effects for three-phase relative permeability. Each phase is modeled separately based on physical inputs that, in part, are proxies to composition. Phase flux calculations from one gridblock to another are also updated without phase labels. The tuned kr-EoS model and updated compositional simulator are demonstrated for simple ternary cases, multicycle three-phase water-alternating-gas (WAG) injection, and three-hydrocarbon-phase displacement with complex heterogeneity. The approach improves the initial estimates and convergence of flash calculations and stability analyses, as well as the convergence in the pressure solvers. The new compositional simulator allows for high-resolution simulation that gives improved accuracy in recovery estimates at significantly reduced computational time.

Effect of Flow Rate on Imbibition Three-Phase Permeabilities and Capillary Pressures

2001 ◽  
Vol 23 (2) ◽  
pp. 127-135 ◽  
Author(s):  
Serhat Akin, M. R. Birol Demiral
Keyword(s):  
Flow Rate ◽  
Three Phase ◽  
Capillary Pressures

The Effects of Inlet Flow Rates and Slenderness Ratio on the Separation Performance of a Horizontal Three-Phase Separator

2021 ◽  
pp. 1-14
Author(s):  
T. G. Ahmed ◽  
P. A. Russell ◽  
N. Makwashi ◽  
F. Hamad ◽  
S. Gooneratne
Keyword(s):  
Flow Rate ◽  
Liquid Flow ◽  
Gas Flow ◽  
Liquid Flow Rate ◽  
Slenderness Ratio ◽  
Cost Optimization ◽  
Minimum Cost ◽  
Separation Performance ◽  
Three Phase ◽  
Gradient Change

Summary In the first part of this work, the development of a capital cost optimization model for sizing three-phase separators was described. The developed model uses generalized reduced gradient nonlinear algorithms to determine the minimum cost associated with the construction of horizontal separators subject to four sets of constraints. In the second part, an experimental test rig was designed and used to investigate the effect of gas flow rate, liquid flow rate, and slenderness ratio (L/D) on the separation performance of horizontal three-phase separators. The results indicated an inverse relationship between an increase in gas and liquid flow rate and the separator outlet quality. It also indicated a direct relationship between an increase in slenderness ratio and separator outlet quality. The results also showed that the gradient change of the percentage of water in the oil outlet with respect to slenderness ratio decreased to ratios of 6:1. Hence, the separation rate increased. At ratios greater than 6:1, the separation still increases, but the gradient change in separation drops off, implying that the benefit in terms of separation is diminishing beyond this point. Therefore, the optimal slenderness ratio for technical reasons is 6:1.

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