scholarly journals Analysis of a model for foam improved oil recovery

2014 ◽  
Vol 751 ◽  
pp. 346-405 ◽  
Author(s):  
P. Grassia ◽  
E. Mas-Hernández ◽  
N. Shokri ◽  
S. J. Cox ◽  
G. Mishuris ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Numerical Schemes ◽  
Improved Oil Recovery ◽  
Heterogeneous Reservoirs ◽  
Long Time ◽  
Porous Reservoir ◽  
Tension Term ◽  
Sharp Corners ◽  
Pressure Driven

AbstractDuring improved oil recovery (IOR), gas may be introduced into a porous reservoir filled with surfactant solution in order to form foam. A model for the evolution of the resulting foam front known as ‘pressure-driven growth’ is analysed. An asymptotic solution of this model for long times is derived that shows that foam can propagate indefinitely into the reservoir without gravity override. Moreover, ‘pressure-driven growth’ is shown to correspond to a special case of the more general ‘viscous froth’ model. In particular, it is a singular limit of the viscous froth, corresponding to the elimination of a surface tension term, permitting sharp corners and kinks in the predicted shape of the front. Sharp corners tend to develop from concave regions of the front. The principal solution of interest has a convex front, however, so that although this solution itself has no sharp corners (except for some kinks that develop spuriously owing to errors in a numerical scheme), it is found nevertheless to exhibit milder singularities in front curvature, as the long-time asymptotic analytical solution makes clear. Numerical schemes for the evolving front shape which perform robustly (avoiding the development of spurious kinks) are also developed. Generalisations of this solution to geologically heterogeneous reservoirs should exhibit concavities and/or sharp corner singularities as an inherent part of their evolution: propagation of fronts containing such ‘inherent’ singularities can be readily incorporated into these numerical schemes.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1402-1415 ◽  
Author(s):  
A. H. Al Ayesh ◽  
R.. Salazar ◽  
R.. Farajzadeh ◽  
S.. Vincent-Bonnieu ◽  
W. R. Rossen
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Model Parameters ◽  
High Permeability ◽  
Fractional Flow ◽  
Injection Method ◽  
Heterogeneous Reservoirs ◽  
Irreducible Water Saturation

Summary Foam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers. Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG process, diversion of the first slug of gas depends on foam behavior at very-high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether foam collapses completely at irreducible water saturation. In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.

Study on Performance Evaluation of Dispersed Particle Gel for Improved Oil Recovery

2013 ◽  
Vol 135 (4) ◽  
Author(s):  
Qing You ◽  
Caili Dai ◽  
Yongchun Tang ◽  
Ping Guan ◽  
Guang Zhao ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Water Flooding ◽  
Improved Oil Recovery ◽  
Hydrocarbon Recovery ◽  
Heterogeneous Reservoirs ◽  
Atomic Force ◽  
Segregated Flow ◽  
Oil Flow

This work investigates the performance of dispersed particle gel (DPG) by core flow tests including injectivity, selective plugging, thermal stability, and improved oil recovery (IOR). Results showed that the resistance factor is small when DPG was injected, but obviously became larger while turning into brine water flooding. Both the oil and water relative permeability were reduced and greater reduction appeared in water relative permeability. DPG could block water flow without affecting oil flow, and oil–water segregated flow mechanism was proposed to explain this selective plugging. The injection pressure increases, caused by strong plugging due to the DPG aggregation aging in high temperature, which was consistent with the observation of atomic force microscope (AFM) photos. The DPG could effectively block high permeability zone and produce oil from low permeability zone, which could provide a practical way to enhance hydrocarbon recovery while reducing water production for extremely heterogeneous reservoirs.

scholarly journals Modelling foam improved oil recovery: towards a formulation of pressure-driven growth with flow reversal

2020 ◽  
Vol 476 (2244) ◽  
pp. 20200573
Author(s):  
M. Eneotu ◽  
P. Grassia
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Reverse Flow ◽  
Flow Direction ◽  
Flow Reversal ◽  
Flow Mode ◽  
Fractional Flow ◽  
Improved Oil Recovery ◽  
Forward Flow ◽  
Pressure Driven

The pressure-driven growth model that describes the two-dimensional (2-D) propagation of a foam through an oil reservoir is considered as a model for surfactant-alternating-gas improved oil recovery. The model assumes a region of low mobility, finely textured foam at the foam front where injected gas meets liquid. The net pressure driving the foam is assumed to reduce suddenly at a specific time. Parts of the foam front, deep down near the bottom of the front, must then backtrack, reversing their flow direction. Equations for one-dimensional fractional flow, underlying 2-D pressure-driven growth, are solved via the method of characteristics. In a diagram of position versus time, the backtracking front has a complex double fan structure, with two distinct characteristic fans interacting. One of these characteristic fans is a reflection of a fan already present in forward flow mode. The second fan however only appears upon flow reversal. Both fans contribute to the flow’s Darcy pressure drop, the balance of the pressure drop shifting over time from the first fan to the second. The implications for 2-D pressure-driven growth are that the foam front has even lower mobility in reverse flow mode than it had in the original forward flow case.

scholarly journals EFFECT OF OPTIMUM SALINITY?ON MICROEMULSION FORMATION TO ATTAIN ULTRALOW INTERFACIAL TENSION FOR CHEMICAL FLOODING APPLICATION

2018 ◽  
Vol 39 (2) ◽  
pp. 63-69
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Surfactant Solution ◽  
Oil Field ◽  
Phase Behaviour ◽  
Major Influence ◽  
Chemical Flooding ◽  
Improved Oil Recovery ◽  
Ultralow Interfacial Tension ◽  
Optimum Salinity

Microemulsion formation in surfactant solution has a major influence on the success of chemical injection techniques, and is one of the enhanced oil recovery methods. Its transparent and translucent homogenous mixtures of oil and water in the presence of surfactant have an ability to displace the remaining oil in the reservoir by reducing interfacial tension between oil and water. In this study, the effect of surfactant solution salinity on the formation of microemulsion and its mechanism to reduce the interfacial tension between water and oil from X oil field in Central Sumatera were carried out through compatibility observation, phase behaviour test and interfacial tension measurements in a laboratory. The results showed that microemulsion formation depends on the salinity of aqueous phase associated with different surfactant solubility by altering the polar area of surfactant. The optimum salinity was obtained with the addition of 0.65% Na2CO3 in which microemulsion was formed and the solubilization ratio of oil and water were equally high. At this condition the ultralow interfacial tension was around 10-3 dyne/cm and enabled improved oil recovery in mature oil fields after waterflooding

Frontal-Stability Analysis of Surfactant Floods

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 471-482 ◽  
Author(s):  
Shayan Tavassoli ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mobility Control ◽  
Surfactant Flooding ◽  
Control Cost ◽  
Fine Grid ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Reservoir Conditions ◽  
The Stability

Summary Recent surfactant-flooding experiments have shown that very-efficient oil recovery can be obtained without mobility control when the surfactant solution is injected at less than the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale on the basis of gravity-stable surfactant-flooding experiments at the laboratory scale. The scaleup process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated 3D heterogeneous reservoirs by use of a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods, and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be performed without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.

scholarly journals Foam front advance during improved oil recovery: similarity solutions at early times near the top of the front

2017 ◽  
Vol 828 ◽  
pp. 527-572 ◽  
Author(s):  
P. Grassia ◽  
L. Lue ◽  
C. Torres-Ulloa ◽  
S. Berres
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Similarity Solutions ◽  
Simulation Data ◽  
Convex Shape ◽  
Improved Oil Recovery ◽  
Lower Region ◽  
Concave Corner ◽  
Front Advance ◽  
Material Points

The pressure-driven growth model is used to determine the shape of a foam front propagating into an oil reservoir. It is shown that the front, idealised as a curve separating surfactant solution downstream from gas upstream, can be subdivided into two regions: a lower region (approximately parabolic in shape and consisting primarily of material points which have been on the foam front continuously since time zero) and an upper region (consisting of material points which have been newly injected onto the foam front from the top boundary). Various conjectures are presented for the shape of the upper region. A formulation which assumes that the bottom of the upper region is oriented in the same direction as the top of the lower region is shown to fail, as (despite the orientations being aligned) there is a mismatch in location: the upper and lower regions fail to intersect. Alternative formulations are developed which allow the upper region to curve sufficiently so as to intersect the lower region. These formulations imply that the lower and upper regions (whilst individually being of a convex shape as seen from downstream) actually meet in a concave corner, contradicting the conventional hypothesis in the literature that the front is wholly convex. The shape of the upper region as predicted here and the presence of the concave corner are independently verified via numerical simulation data.

Influence of chemical composition of mixing water on the gelation of inorganic polymer technology for improved oil recovery

2017 ◽  
Vol 3 (3) ◽  
pp. 33-38 ◽  
Author(s):  
А.V. Аntuseva ◽  
Е.F. Kudina ◽  
G.G. Pechersky ◽  
Y.R. Kuskildina ◽  
А.V., Melgui ◽  
...  
Keyword(s):  
Chemical Composition ◽  
Oil Recovery ◽  
Inorganic Polymer ◽  
Improved Oil Recovery ◽  
Mixing Water

Technologies for improved oil recovery by deep cleaning of the bottom-hole zone of wells with RBS-3 and DGK-2 reagents

2020 ◽  
Vol 7 ◽  
pp. 116-119
Author(s):  
R.N. Fakhretdinov ◽  
◽  
D.F. Selimov ◽  
A.A. Fatkullin ◽  
S.A. Tastemirov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Improved Oil Recovery ◽  
Bottom Hole
Sign in / Sign up

Export Citation Format

Share Document