The Effects of Vertical Fractures on Areal Sweep Efficiency in Adverse Mobility Ratio Floods

1988 ◽  
Author(s):  
C.L. Bargas ◽  
J.L. Yanosik
Keyword(s):  
Mobility Ratio ◽  
Sweep Efficiency ◽  
Adverse Mobility Ratio ◽  
Vertical Fractures

Unit Mobility Ratio Displacement Calculations for Pattern Floods in Homogeneous Medium

1966 ◽  
Vol 6 (03) ◽  
pp. 217-227 ◽  
Author(s):  
Hubert J. Morel-Seytoux
Keyword(s):  
Oil Recovery ◽  
Numerical Solutions ◽  
Mobility Ratio ◽  
Finite Difference Approximation ◽  
Difference Approximation ◽  
Numerical Techniques ◽  
Sweep Efficiency ◽  
Closed Form Solutions ◽  
Regular Patterns ◽  
Quantities Of Interest

Abstract The influence of pattern geometry on assisted oil recovery for a particular displacement mechanism is the object of investigation in this paper. The displacement is assumed to be of unit mobility ratio and piston-like. Fluids are assumed incompressible and gravity and capillary effects are neglected. With these assumptions it is possible to calculate by analytical methods the quantities of interest to the reservoir engineer for a great variety of patterns. Specifically, this paper presentsvery briefly, the methods and mathematical derivations required to obtain the results of engineering concern, andtypical results in the form of graphs or formulae that can be used readily without prior study of the methods. Results of this work provide checks for solutions obtained from programmed numerical techniques. They also reveal the effect of pattern geometry and, even though the assumptions of piston-like displacement and of unit mobility ratio are restrictive, they can nevertheless be used for rather crude but quick, cheap estimates. These estimates can be refined to account for non-unit mobility ratio and two-phase flow by correlating analytical results in the case M=1 and the numerical results for non-Piston, non-unit mobility ratio displacements. In an earlier paper1 it was also shown that from the knowledge of closed form solutions for unit mobility ratio, quantities called "scale factors" could be readily calculated, increasing considerably the flexibility of the numerical techniques. Many new closed form solutions are given in this paper. INTRODUCTION BACKGROUND Pattern geometry is a major factor in making water-flood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected. BACKGROUND Pattern geometry is a major factor in making water-flood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected.

scholarly journals Enhanced Oil Recovery: Chemical Flooding

2021 ◽  
Author(s):  
Ahmed Ragab ◽  
Eman M. Mansour
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Phase ◽  
Mobility Ratio ◽  
Chemical Flooding ◽  
Sweep Efficiency ◽  
Oil Displacement ◽  
Remaining Oil ◽  
Oil Displacement Efficiency

The enhanced oil recovery phase of oil reservoirs production usually comes after the water/gas injection (secondary recovery) phase. The main objective of EOR application is to mobilize the remaining oil through enhancing the oil displacement and volumetric sweep efficiency. The oil displacement efficiency enhances by reducing the oil viscosity and/or by reducing the interfacial tension, while the volumetric sweep efficiency improves by developing a favorable mobility ratio between the displacing fluid and the remaining oil. It is important to identify remaining oil and the production mechanisms that are necessary to improve oil recovery prior to implementing an EOR phase. Chemical enhanced oil recovery is one of the major EOR methods that reduces the residual oil saturation by lowering water-oil interfacial tension (surfactant/alkaline) and increases the volumetric sweep efficiency by reducing the water-oil mobility ratio (polymer). In this chapter, the basic mechanisms of different chemical methods have been discussed including the interactions of different chemicals with the reservoir rocks and fluids. In addition, an up-to-date status of chemical flooding at the laboratory scale, pilot projects and field applications have been reported.

Scale-Dependent Mixing for Adverse Mobility Ratio Flows in Heterogeneous Porous Media

2016 ◽  
Vol 113 (1) ◽  
pp. 29-50 ◽  
Author(s):  
Michael Connolly ◽  
Russell T. Johns
Keyword(s):  
Porous Media ◽  
Heterogeneous Porous Media ◽  
Mobility Ratio ◽  
Adverse Mobility Ratio

The Effect of Induced Vertically-Oriented Fractures on Five-Spot Sweep Efficiency

1968 ◽  
Vol 8 (03) ◽  
pp. 260-268 ◽  
Author(s):  
D.A.T. Donohue ◽  
J.T. Hansford
Keyword(s):  
Production Capacity ◽  
Theoretical Work ◽  
Fracture Pattern ◽  
Flow In Porous Media ◽  
Fracture System ◽  
Sweep Efficiency ◽  
Compass Direction ◽  
Vertical Fracture ◽  
Fluid Displacement ◽  
Vertical Fractures

Abstract Substantial evidence indicates that many petroleum producing horizons contain naturally occurring, ordered fracture systems and that within a particular geologic zone, vertical fractures induced in wellbores often will be directed along a particular compass direction. Both conditions will seriously alter the fluid displacement behavior within reservoirs. In this study the effect of induced fracture orientation and length on sweep efficiency is determined for a five-spot pattern. In general, it is assumed that all wells are fractured and directed along the same compass direction. Using the electrical analog to steady state, two-dimensional fluid flow in porous media, boundary conditions are obtained from which flood fronts are tracked numerically. The numerical computations require a particle tracking routine for approximating flood front histories. It is shown that recovery is sensitive to the length and orientation of fractures for the pattern studied. With the proper design of fracture-pattern systems, recovery can be enhanced considerably. Introduction Hydraulic fracturing introduced in 1949, gave the industry a rather inexpensive means of increasing the fluid injection or production capacity of wells. It has been used with particular success to increase the production rate of wells completed in tight formations, such as in western Pennsylvania where producers have fractured in depleted or near-depleted fields and observed economic responses. Once the natural energy declines in such a reservoir where all wells have been fractured, waterflooding is generally suggested as means of further increasing recovery. Of the dual objective sought in waterflooding -- high injectivity and high break-through sweep efficiency - the former condition can be obtained if all wells in the flood pattern are fractured; the latter condition should depend on the nature of the fracture system. Considerable theoretical work has been published on the nature of fractures induced in boreholes. Although discussion persists concerning the possibility of forming a horizontal at a given point within the wellbore, it is generally conceded that only vertical fractures will develop below a given depth, i.e., where the fracturing pressure is less than the overburden load. Given the fact that fractures will be vertical in most cases of interest, it is also important to know whether there is order to fracture orientations within a given geological region. Kehle has suggested that in tectonically relaxed areas of uncomplicated geology, the stresses are fairly uniform and all fractures in the region should be parallel. Dunlap arrived at a similar conclusion in a theoretical investigation of localized stress conditions surrounding the borehole. He concluded that most vertical fractures are propagated in a preferred azimuthal direction. Fraser and Pettitt, in extending these theoretical suggestions to a specific field case, used an impression packer to record both a vertical fracture and the orientation of this fracture in the wellbore of a well in the Howard Glasscock field, Tex. Use of this information enhanced the waterflood recovery of the field. Anderson and Stahl also used impression packers on three fractured wells in the Allegheny field, N. Y., and found that the fractures were oriented more or less along the same compass direction. Orientation of the fractures in this manner depends on the stress condition within the formation during fracturing. Elkins and Skov have demonstrated that a natural, oriented, vertical fracture system exists within the Spraberry field. SPEJ P. 260ˆ

Areal Sweep Efficiency of Pseudoplastic Fluids in a Five-Spot Hele-Shaw Model

1968 ◽  
Vol 8 (01) ◽  
pp. 52-62 ◽  
Author(s):  
K.S. Lee ◽  
E.L. Claridge
Keyword(s):  
Porous Medium ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Newtonian Fluids ◽  
Mobility Ratio ◽  
Spot Pattern ◽  
Sweep Efficiency ◽  
Flood Water ◽  
Miscible Displacements ◽  
Connate Water

Abstract Areal sweep efficiency of oil displacement by enhanced-viscosity water exhibiting pseudoplastic behavior was measured in a Hele-Shaw model representing one-quarter of a five-spot pattern. The pseudoplasticity of polymer solutions and the velocity distribution in the five-spot pattern produced a condition under which the mobility ratio between the displacing and the displaced fluid could not be assigned a single value. Instead, the movement of the displacement front is governed by local mobility ratios which are also time dependent. The areal sweep at breakthrough with polymer solutions was poorer than the sweep obtained with Newtonian fluids of comparable viscosity. However, the areal sweep and 1 PV throughput was greatly improved as compared to flood water without polymer. It was also demonstrated that, even after the oil-cut had declined to a low value during a regular waterflood, switching to polymer flood efficiently swept out the oil remaining in the model. Introduction The behavior of fluid displacements in isotropic porous media for various patterns of injection and production wells has been extensively investigated. These investigations all concerned Newtonian fluids, i.e., the viscosity of each fluid was constant regardless of flow rate. The generally unfavorable influence on areal sweep efficiency of higher mobility of the displacing fluid as compared to the mobility of the displaced fluid has been established for both miscible and immiscible fluids. The principle was also established that a close correspondence exists between miscible and immiscible flood front behavior, although oil recovery in a waterflood at unfavorable mobility ratio may be less than that observed in a miscible displacement at the same mobility ratio. This is true even when oil recovery is expressed on the basis of movable oil. The reason is that oil saturation only slowly achieves its final value behind the waterflood front in accordance with the Buckley-Leverett simultaneous flow relations. It is convenient to use miscible displacements for laboratory simulation of waterflood frontal advance since the interfacial tension forces which are negligible in proportion to viscous forces on a reservoir scales are thus made nonoperative in the laboratory model. For miscible displacements, the Hele-Shaw type of model adequately represents a porous medium so long as the appropriate scaling rules are observed in its design and operation. During simulation of waterflood front behavior in the laboratory by using miscible displacements, the behavior of connate water may ordinarily be disregarded since it is usually indistinguishable from flood water in this process. However, when the flood water is deliberately thickened to improve the mobility ratio between water and oil, the effect on the sweep efficiency due to generation of a connate water bank during the process must be considered. In a uniform porous medium, such a bank is generated and efficiently displaced by injection of thickened water. The oil originally in-place at the start of the waterflood is then displaced by connate water followed by thickened water. If the flood water must be thickened to obtain a favorable mobility ratio, the mobility of the oil phase is appreciably less than that of the connate water. Hence, the oil phase is inefficiently displaced by the connate water bank, and a considerable proportion of the oil comes in contact with and is displaced by the thickened waterflood front. SPEJ P. 52ˆ

Systematic Modelling of Unstable Displacement

2021 ◽  
Author(s):  
Arne Skauge ◽  
Kenneth Stuart Sorbie ◽  
Iselin Cecilie Salmo ◽  
Tormod Skauge
Keyword(s):  
Single Point ◽  
Viscous Fingering ◽  
Mobility Ratio ◽  
Fluid Viscosity ◽  
Fractional Flow ◽  
Fine Grid ◽  
Rock Heterogeneity ◽  
Unstable Displacement ◽  
The Impact ◽  
Adverse Mobility Ratio

Abstract Modelling unstable displacement is a challenge which may lead to large errors in reservoir simulations. Field scale coarse grid simulations therefore need to be anchored to more reliable fine grid models which capture fluid displacement instabilities in a physically correct manner. In this paper, a recently developed approach for accurately modelling viscous fingering has been applied to various types of unstable displacement. The method involves estimation of dispersivity of the porous medium and length scale of the model to determine the required size of the simulation grid cell. Fractional flow theory is then applied to obtain the correct saturation of the injected phase in the unstable fingers formed due to the adverse mobility ratio. Unstable displacement experiments have been history matched using 2D-imaging of in-situ saturation as a calibration of our method, before carrying out sensitivity calculations on the effect of fluid viscosity, and rock heterogeneity. Our modelling approach allows us to carry out simulations using a conventional numerical simulator using elementary numerical methods (e.g. single-point upstreaming). The methods used to model instability (Sorbie et al, 2020) was originally developed for immiscible water/oil systems. The current paper now presents new results applying this approach to unstable gas displacements, where adverse viscosity ratios may be even higher than in water/oil systems. The displacement with injected gas is shown to be influenced by mass exchanges between the gas and oil as the alternating fluids (water and gas) are injected in WAG processes. Swelling of fingers delay the gas front and WAG processes divert the injected gas and improve sweep efficiency. We have also modelled water-oil displacement at adverse mobility and shown the benefit which is obtained by reducing the instability by adding polymers to viscosify the injected water. The impact of rock heterogeneity has different effect depending on buoyancy forces and the degree of crossflow into the high permeable zones. This paper extends our novel approach to modelling the fine scale distribution of the injected fluids in adverse mobility ratio displacements. This approach has now been applied to both, gas/oil and water/oil systems where viscous fingering is present, either at extremely adverse mobility ratios and/or for reservoirs where the permeability field is very heterogeneous.

A Finite-Element Method for Reservoir Simulation

1981 ◽  
Vol 21 (01) ◽  
pp. 115-128 ◽  
Author(s):  
Larry C. Young
Keyword(s):  
Finite Element ◽  
Finite Element Methods ◽  
Reservoir Simulation ◽  
Finite Differences ◽  
Time Derivative ◽  
Mobility Ratio ◽  
Difference Approximation ◽  
Central Difference ◽  
Fine Grid ◽  
Adverse Mobility Ratio

Abstract Several previous studies have applied finite-element methods to reservoir simulation problems. Accurate solutions have been demonstrated with these methods; however, competitiveness with finite difference has not been established for most nonlinear reservoir simulation problems. In this study a more efficient finite-element procedures is presented and tested. The method is Galerkin-based, and improved efficiency is obtained by combining Lagrange trial functions with Lobatto quadrature in a particular way. The simulation of tracer performance, ion exchange preflush performance, and adverse mobility ratio miscible displacements is considered. For the problems considered, the method is shown to yield accurate solutions with less computing expense than finite differences or previously proposed finite-element techniques. For the special case of linear trial functions, the method reduces to a five-point central difference approximation. In contrast to previously reported results, this approximation is found to simulate adverse mobility ratio displacements without grid orientation sensitivity, provided a sufficiently fine grid is used. Introduction In the past few years several studies have investigated the use of finite-element methods in reservoir simulation. These include single-phase two-component simulations in one1–3 and two4,5 spatial dimensions and two-phase immiscible calculations in both one6–8 and two9,10 dimensions. These studies have demonstrated that the method is capable of giving accurate solutions, particularly for small slug problems and adverse mobility ratio displacements. All these studies used what we term conventional Galerkin finite-element techniques,1 and, unfortunately, these methods have not proved to be cost competitive with finite differences for most nonlinear reservoir simulation problems. A reduction in computing requirements is, therefore, necessary to make finite-element methods truly useful for reservoir simulation. Relative to finite differences, the increased computing requirements of conventional Galerkin-based methods are due to the following.The approximation of time-derivative terms involves the same number of surrounding grid points as the approximation of flow terms; thus, implicit-pressure/explicit-saturation (IMPES) techniques are not possible (see Ref. 12, Chap. 7).The matrices which result from the approximation of flow terms are not nearly so sparse as in finite differences; thus, the solution of matrix problems requires more computation.The computational work required to generate matrix coefficients is considerably greater than with finite differences due to the number of numerical integrations which must be performed.

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