scholarly journals Chemical systems for improved oil recovery: Phase behavior, oil recovery, and mobility control studies

1995 ◽  
Author(s):  
F. Llave ◽  
B. Gall ◽  
H., Scott, L., Cook, I. Gao
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Recovery Phase ◽  
Mobility Control ◽  
Improved Oil Recovery ◽  
Chemical Systems

Synergy of Polymer for Mobility Control and Surfactant for Interface Elasticity Increase in Improved Oil Recovery

2021 ◽  
Author(s):  
Taniya Kar ◽  
Abbas Firoozabadi
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Synergistic Effects ◽  
Water Injection ◽  
Mobility Control ◽  
Residual Oil ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Abstract Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.

CO 2 -sensitive and self-enhanced foams for mobility control during CO 2 injection for improved oil recovery and geo-storage

2017 ◽  
Vol 120 ◽  
pp. 113-120 ◽  
Author(s):  
Dexiang Li ◽  
Shaoran Ren ◽  
Panfeng Zhang ◽  
Liang Zhang ◽  
Yunjun Feng ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Improved Oil Recovery

Use of Cosolvents To Improve Alkaline/Polymer Flooding

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 255-266 ◽  
Author(s):  
R.. Fortenberry ◽  
D.H.. H. Kim ◽  
N.. Nizamidin ◽  
S.. Adkins ◽  
G.W.. W. Pinnawala Arachchilage ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Mobility Control ◽  
Crude Oils ◽  
Heavy Oils ◽  
Low Viscosity ◽  
Low Concentrations ◽  
Wide Range ◽  
Acidic Components

Summary We have found that the addition of low concentrations of certain inexpensive light cosolvents to alkaline/polymer (AP) solutions dramatically improves the performance of AP corefloods in two important ways. First, the addition of cosolvent promotes the formation of low-viscosity microemulsions rather than viscous macroemulsions. Second, these light cosolvents greatly improve the phase behavior in a way that can be tailored to a particular oil, temperature, and salinity. This new chemical enhanced-oil-recovery (EOR) technology uses polymer for mobility control and has been termed alkali/cosolvent/polymer (ACP) flooding. ACP corefloods perform as well as alkaline/surfactant/polymer (ASP) corefloods while being simpler and more robust. We report 12 successful ACP corefloods using four different crude oils ranging from 12 to 24°API. The ACP process shows special promise for heavy oils, which tend to have large fractions of soap-forming acidic components, but is applicable across a wide range of oil gravity.

Anomalous Foam-Fractional-Flow Solutions at High-Injection Foam Quality

2013 ◽  
Vol 16 (01) ◽  
pp. 40-50 ◽  
Author(s):  
A.. Roostapour ◽  
S.I.. I. Kam
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Mobility Control ◽  
Injection Velocity ◽  
Fractional Flow ◽  
Improved Oil Recovery ◽  
High Injection ◽  
Constant State ◽  
Dry Conditions ◽  
First Time

Summary A thorough understanding of foam fundamentals is crucial to the optimal design of foams for improved oil recovery (IOR) or enhanced oil recovery (EOR). This study, for the first time, presents anomalous foam-fractional-flow solutions that deviate significantly from the conventional solutions at high-injection foam qualities by comparing method-of-characteristics and mechanistic bubble-population-balance simulations. The results from modeling and simulations derived from coreflood experiments revealed the following: The fraction of grinding energy contributed by the flowing gas (fg)There are three regions—Region A with relatively wet (or high fw) injection conditions in which the solutions are consistent with the conventional fractional-flow theory; Region C with very dry (or low fw) injection conditions in which the solutions deviate significantly; and Region B in between, which has a negative dfw/dSw slope showing physically unstable solutions.For dry-injection conditions in Region C, the solutions require a constant state (IJ) between initial (I) and injection (J) conditions, forcing a shock from I to IJ by intersecting fractional-flow curves, followed by spreading waves or another shock to reach from IJ to J.The location of IJ in fw vs. Sw domain moves to the left (or toward lower Sw) as the total injection velocity increases for both weak and strong foams until it reaches limiting water saturation. Even though foams at high-injection quality are popular for mobility control associating a minimum amount of surfactant solutions, foam behaviors at dry conditions have not been thoroughly investigated and understood. The outcome of this study is believed to be helpful to the successful planning of foam IOR/EOR field applications.

Development and Evaluation of Locally Made Polymer for Improved Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Peter Peibuluemi Emmanuel
Keyword(s):  
Oil Recovery ◽  
Chemical Properties ◽  
Cassava Starch ◽  
Water Soluble ◽  
Mobility Control ◽  
Polymer Materials ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Improved Oil Recovery ◽  
Polymer Injection

Abstract Hydrocarbons recoveries from matured fileds require enhancement. This is because matured oil fields have undergone pressure depletions. Polymer injection is a proven means of hydrocarbon recovery enhancement. Therefore, search for polymer materials and preparations of polymer, in the vicinity of matured field is the focus of this study. A lead was found in a starch and investigated to cassava tubers. Cassava starch are brine - water soluble, and are used for favorable mobility control. Laboratory tests were conducted for starch solubility and stability at predetermined saline environment and selected ‘reservoir’ temperature and pressure. Physico - chemical properties and other characteristics of the locally sourced polymer were guided by branded commercial polymers. In all, ten batches of laboratory core flooding excercises were conducted on oil-soaked cores, with five different brine concentrations, followed by another five-cassava starch polymer of concentration 0.00 g/l, 4.35 g/L, 5.13 g/L, 7.02 g/L, and 8.81 g/L. The respective polymer viscosities were 0 cp, 1.28 cp, 2.25 cp, 3.30 cp, and 4.15 cp. While the oil sample of 24.27°API at a temparture of 33°C, was used throughout. Respectively, a displacement efficiency of 51.86 %, 51.86 %, 51.85 %, 51.85 %, and 51.86 % were obtained as results.

Rate Effects in Tertiary Micellar Flooding of Bradford Crude Oil

1981 ◽  
Vol 21 (04) ◽  
pp. 469-479 ◽  
Author(s):  
M.H.M. Sayyouh ◽  
S.M. Farouq Ali ◽  
C.D. Stahl
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Rate Effect ◽  
Mobility Control ◽  
Oil Reservoirs ◽  
Micellar Solutions ◽  
Experimental Conditions ◽  
Flow Rates ◽  
Advance Rate ◽  
System Phase

Abstract Micellar flooding of the tight Pennsylvania oil reservoirs invariably is accompanied by low flood advance rates -on the order of a fraction of 1 ft/D. This investigation, therefore, was devoted to the effect of rate on tertiary oil recovery. The experiments were conducted in 2- and 4-ft-long Berea sandstone cores at rates as low as 0.10 ft/D. All runs were tertiary in nature. The micellar solutions being used in the field tests in Pennsylvania also were used for this research. The majority of the runs were carried out in horizontally positioned cores (although a few runs used vertical cores) to determine if gravity was a factor in the observed effect. It was found that oil recovery decreased with a decrease in the flood advance rate up to a point. Thereafter, it showed a small increase with further decrease in rate. This effect has not been reported by other investigators. The rate effect is discussed and analyzed in terms of the system phase behavior, sulfonate adsorption, dispersion, diffusion, and mobility control. The role of the rate effect on the formation of the stabilized bank also was developed for the experimental conditions involved. The implications of very low rates are discussed in the light of field results. Introduction During recent years, much effort has been devoted to investigations of oil displacement by micellar solutions. This process was proposed and described in detail by Gogarty and Tosch1 and Davis and Jones.2 An analysis of the mechanism of the process is given by Bleakley.3 The micellar solutions are composed primarily of a hydrocarbon, water, a surfactant, and a cosurfactant. Micellar flooding involves sequential injection of a micellar slug, a mobility buffer, and drive water. Since one of the significant characteristics of Pennsylvania oil reservoirs is the low formation permeability, water flood rates in many of these reservoirs are much less than 1 ft/D. Currently, tertiary micellar floods are being conducted in these reservoirs. Thus, it is important to investigate the recovery behavior of micellar displacement at comparable flow rates. Taber et al.4 observed that at both higher and lower rates the displacement of oil and water by an alcohol was efficient. This was confirmed later by Taber and Meyer.5 An increase in micro emulsion displacement efficiency at high rates was observed by Healy et al.6 In our previous work,7 the effect of flood advance rate in micellar/polymer displacement process under a wide variety of conditions was investigated to determine (1) what effect do flow rates have on oil recovery and (2) whether flow rate itself or some other factor, such as gravity segregation, contributes to the observed behavior. Oil recovery was found to be rate dependent under these conditions. One objective of this work is to analyze the effect of flood advance rates in terms of system phase behavior, sulfonate adsorption, mixing mechanism, and mobility control. Another purpose is to understand the effect of rate on the formation of the stabilized oil/water bank and discuss the implications of very low rates.

Displacement of Polymers in Waterflooded Porous Media and Its Effects on a Subsequent Micellar Flood

1977 ◽  
Vol 17 (05) ◽  
pp. 358-368 ◽  
Author(s):  
Mahmoud K. Dabbous
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Phase Distribution ◽  
Mobility Control ◽  
Reservoir Rock ◽  
Residual Oil ◽  
Improved Oil Recovery ◽  
Residual Resistance ◽  
Oil Water

Abstract Injection of polymers in advance of a micellar fluid slug has been considered to improve reservoir volumetric sweep in a tertiary-mode micellar flood. An investigation was made of the injection of polyacrylamide-type polymers in waterflooded polyacrylamide-type polymers in waterflooded porous media and its effects on a subsequent porous media and its effects on a subsequent micellar flood. It was found that the presence of waterflood residual oil saturations in the porous medium increased the flow resistance and residual resistance factors (2- to 3.5-fold) compared with their corresponding values when the rock was free of residual oil. Inaccessible pore volume to polymer flow also appeared to be larger when waterflood residual oil saturations were present. These effects have been attributed to wettability and phase distribution of fluids in the porous medium. phase distribution of fluids in the porous medium. The study emphasized basic differences in the flow behavior of polymer injected ahead of a micellar slug (to improve sweep) and behind the micellar fluid (to control mobility). Both effects are for improved oil-recovery efficiency. Water mobility was greatly reduced following the displacement of polyacrylamide polymers in the waterflooded cores, yet mobility of the oil-water bank in a subsequent micellar flood was reduced to a lesser degree than the water bank. For a residual resistance factor to water ranging from 2 to 7, mobility control of a subsequent micellar flood could be achieved with a 22- to 39-percent increase in polymer concentration in the mobility buffer bank. This increase is in excess of the concentration required for a flood not preceded with polymer injection. Polymer preinjection had no adverse effects on oil displacement characteristics of the micellar fluid and appeared to reduce surfactant adsorption on the rock for the polymer-micellar system studied. Some experimental data indicated that the oil bank breaks through earlier and at a slightly higher oil cut in linear core floods. Such a result is theoretically feasible if the reduced-mobility water is not completely displaced at the front end (immiscible portion) of the oil-water bank. Oil-bank breakthrough probably would be delayed in the reservoir because of the action of the preinjected polymer to decrease the flow of fluids in polymer to decrease the flow of fluids in high-permeability zones. Introduction In a previous paper, preinjection of polymers in advance of a micellar slug was proposed as a means for improving reservoir volumetric sweep and oil recovery by a micellar flood. Increased flooding efficiency should result from reduced interwell permeability contrast in the reservoir following the polymer treatment. Preinjection of polymers also should result in better preflushing polymers also should result in better preflushing efficiency in displacing incompatible formation brines over "conventional" water preflushes. Thus, an improved oil-recovery method designed to increase reservoir volumetric sweep and miscibly recover tertiary oil consists ofpreinjection of a carefully designed slug of preinjection of a carefully designed slug of high-molecular-weight polyacrylamide polymers followed by a water-bank spacer to displace the polymer in the interwell area, andinjection of polymer in the interwell area, andinjection of a surfactant (micellar) slug followed by a polymer mobility buffer bank and chase water. The fluid banks that are injected or developed during the process are illustrated in Fig. 1. Mixing and process are illustrated in Fig. 1. Mixing and interaction zones at fluid-bank boundaries are not shown in the schematic. The preinjection of a polymer is intended to rectify interwell permeability variation. The polymer is injected in reservoir rock that has waterflood residual oil saturations. SPEJ p. 358

Effect of Nanoscale Pore-Size Distribution on Fluid Phase Behavior of Gas-Improved Oil Recovery in Shale Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (03) ◽  
pp. 1406-1415
Author(s):  
Sheng Luo ◽  
Jodie L. Lutkenhaus ◽  
Hadi Nasrabadi
Keyword(s):  
Pore Size Distribution ◽  
Phase Behavior ◽  
Pore Size ◽  
Size Distribution ◽  
Oil Recovery ◽  
Gas Injection ◽  
Fluid Phase ◽  
Improved Oil Recovery ◽  
Nanoscale Pore ◽  
Shale Reservoirs

Summary The improved oil recovery (IOR) of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as carbon dioxide (CO2) and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low-permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of a gas-injection operation. Shale reservoirs typically have macroscale to nanoscale pore-size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores, the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain. In this study, we investigate the nanoscale pore-size-distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs. A case of Anadarko Basin shale oil is used. The pore-size distribution is discretized as a multiscale system with pores of specific diameters. The phase equilibria of methane injection into the multiscale system are calculated. The constant-composition expansions are simulated for oil mixed with various fractions of injected gas. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure to less than the bubblepoint turns it into the subcritical state. The bubblepoint is generally lower than the bulk and the degree of deviation depends on the amount of injected gas. The modeling of confined-fluid swelling shows that fluid swelled from nanopores is predicted to contain more oil than the swelled fluid at bulk state.

scholarly journals Evaluation of the Foamability Potential of a Novel Biosurfactant Using the Solution to Advective-Diffusive Transport Model in Porous Media With a Linear Adsorption Trend

2018 ◽  
Vol 10 (2) ◽  
pp. 56
Author(s):  
Mumuni Amadu ◽  
Adango Madongye
Keyword(s):  
Carbon Dioxide ◽  
Analytical Solution ◽  
Oil Recovery ◽  
Transport Model ◽  
Petroleum Industry ◽  
Mobility Control ◽  
Saline Aquifers ◽  
Adsorption Model ◽  
Geological Sequestration ◽  
Improved Oil Recovery

While geological sequestration of anthropogenic carbon dioxide is a technically and economically viable option for reducing emissions to the level required to avoid the predicted 2 degrees Celsius increase of atmospheric temperature by the end of this century, efficient sequestration planning is vital for the achievement of this goal.The petroleum industry has used conventional surfactants in enhance oil recovery projects aimed at prolonging the life span of a field, thereby increasing ultimate reserves. Notable among these is the use of surfactants for injected gas relative mobility control. Therefore, the potential for carbon dioxide mobility control in saline aquifers using surfactant alternating gas injection is huge, given the rich experience that can be tapped from the petroleum industry practice.Considering the expected surfactant loses in surfactant-enhanced geological sequestration similar to that encountered in the petroleum industry, this paper has used the analytical solution to advective diffusive equation that exists in the literature with a linear adsorption model where, adsorption has been used to predict trends in minimum pressure drop required for foam generation. The greatest utility of this work lies in the fact that the analytical solution is related a linear adsorption model related to a novel surfactant found from biological and hydrocarbon sources of geologic origin. This paper, therefore, extends the work of linear adsorption models for this novel surfactant aimed at exploring improved oil recovery potentials; in addition to exploring its potential for efficient geological carbon storage in saline aquifers.

Scale-Up Evaluations and Simulations of Mobility Control Foams for Improved Oil Recovery

Surfactants ◽  
2000 ◽  
pp. 251-292 ◽  
Author(s):  
Fred Wassmuth ◽  
Laurier L. Schramm ◽  
Karin Mannhardt ◽  
Laurie Hodgins
Keyword(s):  
Oil Recovery ◽  
Scale Up ◽  
Mobility Control ◽  
Improved Oil Recovery
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