Can Formation Relative Permeabilities Rule Out a Foam EOR Process?

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 340-351 ◽  
Author(s):  
E.. Ashoori ◽  
W.R.. R. Rossen
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Leading Edge ◽  
Geometric Constraints ◽  
Naturally Fractured Reservoirs ◽  
Flow Diagram ◽  
Relative Permeabilities ◽  
Fractional Flow ◽  
Straight Line ◽  
Gas Mobility

Summary Foam is a promising means of increasing sweep in miscible- and immiscible-gas enhanced oil recovery (EOR). Surfactant alternating gas (SAG) is a preferred method of injection. Numerous studies verify that the water relative permeability function krw(Sw) is unaffected by foam. Studies of foam have used a variety of krw functions. This paper shows a connection between the krw(Sw) function and SAG foam effectiveness that is independent of the details of how foam reduces gas mobility. For simplicity, we analyze SAG processes in the absence of mobile oil; success without oil is a precondition to success with oil, and our analysis also applies to a miscible-gas process with oil in 1D in the absence of dispersion. Fractional-flow methods have proved useful and accurate for modeling foam EOR processes. The success of SAG depends on total mobility at a point of tangency to the fractional-flow curve, which defines the shock front at the leading edge of the foam bank. One can determine total mobility directly from the coordinates of this point (Sw, fw) if the function krw(Sw) is known. Geometric constraints limit the region in the fractional-flow diagram in which this point of tangency can occur. For a given krw(Sw) function, this limits the mobility reduction achievable for any possible SAG process. We examine the implications of this limitation for different krw functions. These implications include the following. Increasing nonlinearity of the krw function is advantageous for SAG processes, regardless of how foam reduces gas mobility. SAG is inappropriate for naturally fractured reservoirs if straight-line relative permeabilities apply, even if extremely strong foam can be stabilized in fractures. It is important to measure krw(Sw) separately for any formation for which a SAG process is envisioned.

Experimental Study of Foam Generation, Sweep Efficiency, and Flow in a Fracture Network

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1140-1150 ◽  
Author(s):  
M. A. Fernø ◽  
J.. Gauteplass ◽  
M.. Pancharoen ◽  
A.. Haugen ◽  
A.. Graue ◽  
...  
Keyword(s):  
Flow Behavior ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Fracture Network ◽  
Mobility Control ◽  
Fractional Flow ◽  
Sweep Efficiency ◽  
Foam Generation ◽  
Gas Mobility ◽  
Mobility Reduction

Summary Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.

A Sensitivity Study of Micellar/Polymer Flooding

1979 ◽  
Vol 19 (06) ◽  
pp. 357-368 ◽  
Author(s):  
G.A. Pope ◽  
Ben Wang ◽  
Kerming Tsaur
Keyword(s):  
Ion Exchange ◽  
Oil Recovery ◽  
Sensitivity Study ◽  
Type Ii ◽  
Point Location ◽  
Relative Permeabilities ◽  
Fractional Flow ◽  
Plait Point ◽  
Type Iii ◽  
Capillary Desaturation

Abstract The compositional simulator of Pope and Nelson has been extended to include a number of additional effects. The efficiency of the oil displacement has been calculated as a function of slug size, polymer drive size, surfactant and oil concentrations in the slug, slug/oil bank and drive/slug mobility ratios, surfactant and polymer absorption, interfacial tension (IFT), phase type, binodal curves, plait point location, capillary desaturation curves for each point location, capillary desaturation curves for each phase, relative permeabilities, waterflood residuals, phase, relative permeabilities, waterflood residuals, dispersion, electrolyte gradient, and amount of surfactant injected. High-concentration slugs in a Type II (+) (or plait point left) phase environment were found to be less dependent on low IFT than low-concentration slugs or slugs in a type II (-) phase environment. For the Type II (-) case, oil phase environment. For the Type II (-) case, oil recovery is not sensitive to plait point location. However, the best oil recovery for a given amount of injected surfactant occurs where a salinity higher than optimal exists downstream of the slug and a salinity lower than optimal exists upstream of the slug (in the polymer drive) and the slug itself traverses as much of the reservoir as possible in the low-tension Type III environment. The low final salinity promotes low final retention of surfactant. For the cases studied, the salinity, surfactant concentration, oil concentration, and polymer concentration of the slug itself then made relatively little difference. Introduction Several authors have examined one-dimensional simulation of surfactant flooding and the various complex compositional effects that occur during the displacement of oil with surfactants and polymers. Nelson and Pope presented laboratory results showing the importance of the Type III phase environment and how oil recovery can result from mechanisms other than low IFT. Actually, several key phenomena affecting oil recovery are strongly coupled and need to be considered simultaneously both to understand and to simulate the process. The simulator of Pope and Nelson was a first attempt to model these effects, which include IFT, phase behavior, fractional flow, adsorption, and polymer properties as a function of electrolyte. Ion exchange properties as a function of electrolyte. Ion exchange has been shown to have an important impact on the process as well, since the electrolyte environment process as well, since the electrolyte environment affects many of the most important fluid properties involved. Pope and Nelson have shown how the displacement of oil is "miscible-like" under certain conditions, even when dispersion and adsorption are considered and small slugs are used. However, to be practical, a very carefully designed electrolyte practical, a very carefully designed electrolyte gradient must exist (or some other equivalent gradient of another variable such as surfactant molecular weight, alcohol, etc.). Here we continue the investigation of these process variables by presenting results of a sensitivity study. Both presenting results of a sensitivity study. Both water and oil-rich surfactant slug cases are simulated. Model Changes Pope and Nelson presented a description of the Pope and Nelson presented a description of the original simulator. Several changes that have been made will be discussed briefly. The IFT functions are now those proposed by Healy and Reed. ....... (1) ....... (2) SPEJ P. 357

Evaluation of Foam-Gels for Conformance Control in High Temperature High Salinity Carbonates

2021 ◽  
Author(s):  
Lyla Almaskeen ◽  
Abdulkareem AlSofi ◽  
Jinxun Wang ◽  
Ziyad Kaidar
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Concentration Ratio ◽  
High Salinity ◽  
Fractured Reservoirs ◽  
Gelation Time ◽  
Resistance Factor ◽  
Naturally Fractured Reservoirs ◽  
Conformance Control ◽  
Wide Range

Abstract In naturally fractured reservoirs, conformance control prior to enhanced oil recovery (EOR) application might be essential to ensure optimal contact and sufficient sweep. Recently, few studies investigated combining foams and gels into what is commonly coined as foamed-gels. Foamed-gels have been tested and shown to be potential for some field conditions. Yet, very limited studies were performed for high temperature and high salinity carbonates. Therefore, in this work, we study the potential of foamed-gels for high temperature and high salinity carbonates. The objective is to evaluate the potential of such synergy and to compare its value to the individual processes. For that purpose, in this work, we rely on bulk and core-scale tests. Bulk tests were used for initial screening. Wide range of foam-gel solutions were prepared with different polymer types and polymer concentrations. Test tubes were hand shacked thoroughly to generate foams. Foam heights were then measured from the test tubes. Heights were used to screen foaming agents and to study gelant effects on foamers in terms of foam strength (heights). The effect of foamers on gelation was evaluated through bottle tests. Based on the results, an optimal concentration ratio of gelant to foamer was determined and used in core-scale displacements, to further study the potential of this hybrid foam-gel process. Bulk results suggested that addition of the gelant up to a 4:1 foam to gel concentration ratio resulted in sufficient foam generation in some of the polymer samples. Yet, only two of the foam-gel samples generated a strong gel. Increasing the foamer concentration delayed the gelation time and in some samples, the solution did not gel. Through the coreflooding experiment, resistance factor (RF) and residual resistance factor (RRF) were obtained for different conformance control processes including foam, foam-gel, and gel. Foam-gel injection exhibited higher RF and RRF values than conventional foams. However, conventional gels showed even higher RF and RRF values than foam-gels. Combining two of the most widely used conformance control methods (foams and gels) can strike a balance. Foam-gel may offer a treatment that is deeper and more sustainable than foams and on the other a treatment that is more practical, and lower-cost than gels. Our laboratory results also demonstrate that such synergetic conformance control can be achieved in high salinity and high temperature carbonates with pronounced impact.

Problems in Characterization of Naturally Fractured Reservoirs From Well Test Data

1985 ◽  
Vol 25 (03) ◽  
pp. 445-450 ◽  
Author(s):  
I. Ershaghi ◽  
R. Aflaki
Keyword(s):  
Test Data ◽  
Transition Period ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Late Time ◽  
Time Data ◽  
Straight Line ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
The Matrix

Abstract This paper presents a critical analysis of some recently published papers on naturally fractured reservoirs. These published papers on naturally fractured reservoirs. These publications have pointed out that for a publications have pointed out that for a matrix-to-fracture-gradient flow regime, the transition portion of pressure test data on the semilog plot develops a portion of pressure test data on the semilog plot develops a slope one half that of the late-time data. We show that systems under pseudosteady state also may develop a 1:2 slope ratio. Examples from published case studies are included to show the significant errors associated with the characterization of a naturally fractured system by using the 1:2 slope concept for semicomplete well tests. Introduction Idealistic models of the dual-porosity type often have been recommended for interpretation of a well test in naturally fractured reservoirs. The evolutionary aspects of these models have been reviewed by several authors. Gradual availability of actual field tests and recent developments in analytical and numerical solution techniques have helped to create a better understanding of application and limitation of various proposed models. Two important observations should be made here. First, just as it is now recognized that classical work published by Warren and Root in 1963 was not the end of the line for interpretation of the behavior of naturally fractured systems, the present state of knowledge later may be considered the beginning of the technology. Second, parallel with the ongoing work by various investigators who progressively include more realistic assumptions in their progressively include more realistic assumptions in their analytical modeling, one needs to ponder the implication of these findings and point out the inappropriate impressions that such publications may precipitate in the mind of practicing engineers. practicing engineers. This paper is intended to scrutinize statements published in recent years about certain aspects of the anticipated transition period developed on the semilog plot of pressure-drawdown or pressure-buildup test data. pressure-drawdown or pressure-buildup test data. The Transition Period In the dual-porosity models published to date, a naturally fractured reservoir is assumed to follow the behavior of low-permeability and high-storage matrix blocks in communication with a network of high-permeability and low-storage fractures. The difference among the models has been the assumed geometry of the matrix blocks or the nature of flow between the matrix and the fracture. However, in all cases, it is agreed that a transition period develops that is strictly a function of the matrix period develops that is strictly a function of the matrix properties and matrix-fracture relationship. Fig. 1 shows properties and matrix-fracture relationship. Fig. 1 shows a typical semilog plot depicting the transition period and the parallel lines. Estimation of Warren and Root's proposed and to characterize a naturally fractured proposed and to characterize a naturally fractured system requires the development of the transition period. The Warren and Root model assumes a set of uniformly distributed matrix blocks. Furthermore, the flow from matrix to fracture is assumed to follow a pseudosteady-state regime. Under such conditions, in theory, this period is an S-shaped curve with a point of inflection. Uldrich and Ershaghi developed a technique to use the coordinates of this point of inflection for estimating and under conditions where either the early- or the late-time straight lines were not available. Kazemi and de Swann presented alternative approaches to represent naturally fractured reservoirs. They assumed a geometrical configuration consisting of layered matrix blocks separated by horizontal fractures. Their observation was that for such a system the transition period develops as a straight line with no inflection point. Bourdet and Gringarten identified a semilog straight line during the transition period for unsteady-state matrix-fracture flow. Recent work by Streltsova and Serra et al emphasized the transient nature of flow from matrix to fracture and pointed out the development of a unique slope ratio. These authors, later joined by Cinco-L. and Samaniego-V., stated that under a transient flow condition, the straight-line shape of the transition period develops a slope that is numerically one-half the slope of the parallel straight lines corresponding to the early- or late-time data. It was further pointed out that the transient flow model is a more realistic method of describing the matrix-fracture flow. As such, they implied that in the absence of wellbore-storage-free early-time data, or late-time data in the case of limited-duration tests, one may use the slope of the transition straight line and proceed with the estimation of the reservoir properties. Statement of the Problem The major questions that need to be addressed at this time are as follows. SPEJ P. 445

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