Static and Dynamic Adsorption of Anionic and Nonionic Surfactants

1977 ◽  
Vol 17 (05) ◽  
pp. 337-344 ◽  
Author(s):  
F.J. Trogus ◽  
T. Sophany ◽  
R.S. Schechter ◽  
W.H. Wade
Keyword(s):  
Hydrogen Bonding ◽  
Oil Recovery ◽  
Nonionic Surfactants ◽  
Anionic Surfactants ◽  
Breakthrough Curves ◽  
Dynamic Adsorption ◽  
Surfactant Adsorption ◽  
Chemical Flooding ◽  
Divalent Ions ◽  
Adsorption And Desorption

Abstract The adsorption of commercial polyoxyethylene nonyl phenols and alkyl benzene sulfonates was studied by measuring the surfactant breakthrough from Berea cores. A rate model that reduces to a Langmuir-type isotherm at equilibrium represented these dynamic results and predicted successfully the equilibrium isotherms determined by static experiments.The ratios of both adsorption and desorption were determined and were observed to increase with the number of ethylene oxide groups. Adsorption of the nonionic surfactant appeared to be by hydrogen bonding and the amount adsorbed per unit of area was the same on a number of metal oxide substrates.Negligible adsorption was observed for sulfonates with an alkyl chain length of 9 or less. Introduction Surfactant adsorption is one of the important features governing the economic viability of chemical flooding processes. However, the adsorption on mineral oxide surfaces is only one of several possible mechanisms leading to surfactant losses.Other mechanisms include precipitation of surfactant in the presence of divalent ions, diffusion of surfactant into dead-end pores, and surfactant partitioning into the oil phase. It is necessary partitioning into the oil phase. It is necessary to minimize the losses by all mechanisms. The work reported here addresses the problem of surfactant adsorption; other mechanisms are not considered.There are a number of approaches that have the potential for minimizing adsorption. The most potential for minimizing adsorption. The most desirable surfactant is one that does not adsorb at all; however, such surfactants may not be effective oil-recovery agents. Sacrificial agents that adsorb in place of the surfactant can be used in a preflush or as a competitive additive to the surfactant slug, but effective agents have not yet been identified.Two aspects of the adsorption process are of interest the rate and the amount adsorbed. Both are examined here. The measurements include the dynamic adsorption of both anionic and nonionic surfactants in Berea cores that are initially filled with brine. The breakthrough curves are represented successfully using a model that accounts for the surface coverage. The rate expression reduces to a Langmuir-type isotherm. The shape of this curve has been verified by conducting static experiments.The study included both nonionic and anionic surfactants. These were not pure surfactants but, in general, they are well characterized. The anionic surfactants were studied because their behavior should-be representative of more complex mixtures such as the petroleum sulfonates that have been regarded as prime candidates for oil-recovery agents. These sulfonates are sensitive to divalent ions and many chemical slugs include quantities of nonionic surfactants to alleviate this difficulty to some extent. Therefore, this study included a systematic study of a particular class of nonionic surfactants. This study is the first to report rates of adsorption and desorption. From this information, the nature of the adsorption can be better understood. THEORY Michaels and Morelos have established that the adsorption of polyanions on kaolin occurs by hydrogen bonding. The specific sites at which this adsorption takes place were not defined. For the adsorption of surfactants, this mechanism can be represented as follows: ....................... (1) SPEJ p. 337

The Effect of Oil/Brine Ratio on Surfactant Adsorption From Microemulsion

1981 ◽  
Vol 21 (04) ◽  
pp. 500-512 ◽  
Author(s):  
K.O. Meyers ◽  
S.J. Salter
Keyword(s):  
Oil Recovery ◽  
Pore Volume ◽  
Surfactant Concentration ◽  
Petroleum Industry ◽  
Phase Region ◽  
Retention Data ◽  
Surfactant Adsorption ◽  
Divalent Ions ◽  
Rock Density ◽  
Mass Ratios

Abstract Static adsorption measurements of petroleum sulfonates on crushed Bell Creek and Berea cores were made using fluids with the same active surfactant concentration but varying brine/oil mass ratios. The salinity of the brine was chosen such that a significant three-phase region existed in the oil/brine/surfactant/alcohol system. The surfactant adsorption was found to be independent of the structural and compositions differences among the fluids. A series of oil recovery tests in which middle-phase microemulsions were injected into waterflooded cores also were performed. The cores used in these tests had been treated to remove divalent ions accessible to fluid flow. Microemulsion slugs (1.75 to 146% PV) of equal active surfactant concentration but differing brine/oil mass ratios were injected. The total surfactant retention for this system was also found to be independent of the brine/oil mass ratio. Introduction Control of sulfonate loss is one of the single most important factors in determining the success or failure of a surfactant flooding process. In a typical surfactant flood, sulfonate costs are frequently half or more of the total project cost. As a result, this area has been studied frequently. Many authors have studied detailed adsorption mechanisms - mostly from aqueous solutions and at relatively low concentrations. A recent thesis from the U. of Texas1 and its references provide an excellent description of this type of work. The petroleum industry literature deals more with evaluating the controlling factors in actual flood implementation. Surfactant loss has been broken down into adsorption, precipitation, and phase trapping. The effects of sacrificial agents, sulfonate fractionation, divalent ions, and salinity gradients all have been investigated. Since it is not the purpose of this paper to provide a review of the literature, we have attempted only to summarize some of this literature in the form of a table (see Table 1). Surfactant retention data have been presented in terms of a wide variety of units. These fall into two basic categories: molecules per unit area, which is indicative of surface coverage, and mass per unit of pore volume, which is indicative of surfactant consumption by the reservoir. We have chosen to express both our data and all of the data in Table 1 as microequivalents per square meter (µeq/m2) and milligrams active surfactant per milliliter of pore volume (mg AS/mL PV). In many cases this involved making assumptions as to rock density, porosity, surfactant equivalent weight, etc.; however, it has the advantage of allowing direct comparison of results.

Experimental Investigation of Dynamic Adsorption–Desorption of New Nonionic Surfactant on Carbonate Rock: Application to Enhanced Oil Recovery

2017 ◽  
Vol 139 (4) ◽  
Author(s):  
Ali Barati-Harooni ◽  
Adel Najafi-Marghmaleki ◽  
Seyed Moein Hosseini ◽  
Siyamak Moradi
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Surfactant Concentration ◽  
Water Injection ◽  
Second Order ◽  
Dynamic Adsorption ◽  
Desorption Process ◽  
Adsorption And Desorption ◽  
Short Period ◽  
Pseudo Second Order

Surfactants have the potential to reduce the interfacial tension between oil and water and mobilize the residual oil. An important process which makes the surfactant injection to be less effective is loss of surfactant to porous medium during surfactant flooding. This study highlights the results of a laboratory study on dynamic adsorption and desorption of Trigoonella foenum-graceum (TFG) as a new nonionic surfactant. The experiments were carried out at confining pressure of 3000 psi and temperature of 50 °C. Surfactant solutions were continuously injected into the core plug at an injection rate of 0.5 mL/min until the effluent concentration was the same as initial surfactant concentration. The surfactant injection was followed by distilled water injection until the effluent surfactant concentration was reduced to zero. The effluent concentrations of surfactant were measured by conductivity technique. Results showed that the adsorption of surfactant is characterized by a short period of rapid adsorption, followed by a long period of slower adsorption, and also, desorption process is characterized by a short, rapid desorption period followed by a longer, slow desorption period. The experimental adsorption and desorption data were modeled by four well-known models (pseudo-first-order, pseudo-second-order, intraparticle diffusion, and Elovich models). The correlation coefficient of models revealed that the pseudo-second-order model predicted the experimental data with an acceptable accuracy.

A Systematic Laboratory Approach to Low-Cost, High-Performance Chemical Flooding

2009 ◽  
Vol 12 (05) ◽  
pp. 713-723 ◽  
Author(s):  
Adam Flaaten ◽  
Quoc P. Nguyen ◽  
Gary A. Pope ◽  
Jieyuan Zhang
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
High Performance ◽  
Low Cost ◽  
Surfactant Adsorption ◽  
Chemical Flooding ◽  
Chemical Mixtures ◽  
Asp Flooding ◽  
Saline Brine

Summary We present a systematic study of laboratory tests of alternative chemical formulations for a chemical flood design and application. Aqueous and microemulsion phase behavior tests have previously been shown to be a rapid, inexpensive, and highly effective means to select the best chemicals and minimize the need for relatively expensive coreflood tests. Microemulsion phase behavior testing was therefore conducted using various combinations of surfactants, cosolvents, and alkalis with a particular crude oil and in reservoir conditions of interest. Branched alcohol propoxy sulfates and internal olefin sulfonates showed high performance in these tests, even when mixed with both conventional and novel alkali agents. Systematic screening methods helped tailor and fine tune chemical mixtures to perform well under the given design constraints. The best chemical formulations were validated in coreflood experiments, and compared in terms of both oil recovery and surfactant retention in cores. Each of the four best formulations tested in corefloods gave nearly 100% oil recovery and very low surfactant adsorption. The two formulations with conventional and novel alkali agents gave almost zero surfactant retention. In standard practice, soft water must be used with alkali, but we show how alkali-surfactant-polymer (ASP) flooding can be used in this case even with very hard saline brine. Introduction Many mature reservoirs under waterflood have low economic production rates despite having as much as 50 to 75% of the original oil still in place. These reservoirs are viable candidates for chemical enhanced oil recovery (EOR) that uses both surfactant to reduce oil/water interfacial tension (IFT) and polymer to improve sweep efficiency. However, designing these aqueous chemical mixtures is complex and must be tailored to the reservoir rock and fluid (i.e., crude oil and formation brine) properties of the application. The early success of a systematic laboratory approach to low-cost, high performance chemical flooding depends on the efficiency of designing a formula for coreflood injection in accordance with sound evaluation criteria. A general, a three-stage procedure has been developed previously to screen hundreds of potential chemicals (i.e., surfactant, cosurfactant, cosolvent, alkali, polymer, and electrolytes), and arrive at a mixture having good recovery of residual oil in cores (Jackson 2006; Levitt 2006; Levitt et al. 2006). Additionally, furthering laboratory and field-testing in this area contributes to an expanding research database to help broaden reservoir types that can become candidates for routine chemical EOR application. This paper describes a systematic laboratory approach to low cost, high performance chemical flooding, and explores novel approaches to ASP flooding in reservoirs containing very hard saline brines. The design strategy first uses microemulsion phase behavior experiments to quickly select and optimize concentrations of injected chemicals. Assessment of formula optimization strategies are carried out through varying surfactant-to-cosurfactant ratio, reducing cosolvent concentration, reducing total surfactant concentration, selecting a suitable alkali, and using formation brine in the injection mixture. Formulations performing well in phase behavior are validated in coreflood experiments that adhere to necessary design criteria such as pressure and salinity gradients, surfactant adsorption, and capillary effects. We illustrate the application of our design approach in prepared Berea sandstone cores previously waterflooded with very hard saline brine, and show how ASP flooding can use some of the same brine in the chemical formulation. Conventional ASP flooding requires soft water that may not always be available, and softening hard brines can be very costly or infeasible in many cases depending on the location and other factors. These new results demonstrate high tolerance to both salinity and hardness of the high performance surfactants, and how novel alkalis--in particular sodium metaborate--can provide similar benefits in such harsh environments as sodium carbonate has shown in environments without divalent cations. This experimental success begins to vastly increase the range of conditions for economical EOR using chemicals.

Adsorption of Anionic Surfactants in Sandstones: Impact of Sacrificial Agents

2021 ◽  
Author(s):  
Gulcan Bahar Koparal ◽  
Himanshu Sharma ◽  
Pathma J. Liyanage ◽  
Krishna K. Panthi ◽  
Kishore Mohanty
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Anionic Surfactants ◽  
Cost Effective ◽  
Base Case ◽  
Retention Data ◽  
Surfactant Adsorption ◽  
Surfactant Phase ◽  
Sacrificial Agent ◽  
Ultralow Interfacial Tension

Abstract High surfactant adsorption remains a bottleneck for a field-wide implementation of surfactant floods. Although alkali addition lowers surfactant adsorption, alkali also introduces many complexities. In our systematic study, we investigated a simple and cost effective method to lower surfactant adsorption in sandstones without adding unnecessary complexities. Static and dynamic surfactant adsorption studies were conducted to understand the role of sacrificial agent sodium polyacrylate (NaPA) on adsorption of anionic surfactants n outcrop and resevoir sandstone corefloods. The dynamic retention studies were conducted with and without the presence of crude oil. Surfactant phase behavior studies were first conducted to identify surfactant blends that showed ultralow interfacial tension (IFT) with two crude oils at reservoir temperature (40°C). Base case dynamic retention data, in the absence of crude oil, was obtained for these surfactant formulations at their respective optimum salinities. NaPA was then added to these surfactant formulations and similar adsorption tests were conducted. Finally, oil recovery SP corefloods were conducted for each surfactant formulations, with and without adding NaPA, and oil recovery data including the surfactant retention was compared. Static adsorption of these surfactant formulations at their respective optimum salinities on crushed sandstone varied from 0.42-0.74 mg/g-rock. Their respective adsorptions lowered to 0.37-0.49 mg/g-rock on adding a small amount of NaPA. Surfactant retention in single-phase dynamic SP corefloods in the absence of crude oil in outcrop Berea cores was between 0.17 to 0.23 mg/g-rock. On adding a small amount of NaPA, the surfactant adsorption values lowered to 0.1 mg/g-rock. Oil recovery SP corefloods showed high oil recovery (~91% ROIP) and low surfactant retention (~0.1 mg/g-rock) on adding NaPA to the surfactant formulations.

Adsorption Inhibitor Role in a Constant Salinity Surfactant-Polymer CSSP Flooding Design for an Offshore Field Application

2021 ◽  
Author(s):  
Arif Azhan Abdul Manap ◽  
Nazliah Nazma Zulkifli
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Field Application ◽  
Alternative Formulation ◽  
Surfactant Adsorption ◽  
Chemical Flooding ◽  
Acid Type ◽  
Injection Water ◽  
Additional Water ◽  
Offshore Field

Abstract A base chemical flooding formulation using alkaline-surfactant-polymer (ASP) has been developed for application in offshore environments. The formulation uses combination of conventional alkali (sodium carbonate) with amphoteric surfactant. The field is currently under waterflooding using sea water as injection water. However, since alkali is incompatible with divalent ions in sea water, an alternative formulation using seawater with no additional water treatment is also being developed and considered for application. The alternative formulation uses combination of alkyl propoxy sulfate (APS) and alkyl ethoxy sulfate (AES). Coreflood recovery performance of both formulations is similar. Without alkali, high surfactant adsorption becomes major concern for the alternative formulation. Thus, an adsorption inhibitor (AI) agent – polyacrylic acid type, is being considered as an additive to address this concern. While AI showed potential in reducing surfactant adsorption and improving oil recovery efficiency, it can also increase overall cost for the surfactant in sea water chemical formulation. Hence, the merit to apply AI was not clearly observed.

A Ternary, Two-Phase, Mathematical Model of Oil Recovery With Surfactant Systems

1984 ◽  
Vol 24 (06) ◽  
pp. 606-616 ◽  
Author(s):  
Charles P. Thomas ◽  
Paul D. Fleming ◽  
William K. Winter
Keyword(s):  
Mathematical Model ◽  
Oil Recovery ◽  
Arbitrary Number ◽  
The Other ◽  
Phase System ◽  
Chemical Flooding ◽  
Two Phase ◽  
Oil Displacement ◽  
Surfactant Systems ◽  
And Diffusion

Abstract A mathematical model describing one-dimensional (1D), isothermal flow of a ternary, two-phase surfactant system in isotropic porous media is presented along with numerical solutions of special cases. These solutions exhibit oil recovery profiles similar to those observed in laboratory tests of oil displacement by surfactant systems in cores. The model includes the effects of surfactant transfer between aqueous and hydrocarbon phases and both reversible and irreversible surfactant adsorption by the porous medium. The effects of capillary pressure and diffusion are ignored, however. The model is based on relative permeability concepts and employs a family of relative permeability curves that incorporate the effects of surfactant concentration on interfacial tension (IFT), the viscosity of the phases, and the volumetric flow rate. A numerical procedure was developed that results in two finite difference equations that are accurate to second order in the timestep size and first order in the spacestep size and allows explicit calculation of phase saturations and surfactant concentrations as a function of space and time variables. Numerical dispersion (truncation error) present in the two equations tends to mimic the neglected present in the two equations tends to mimic the neglected effects of capillary pressure and diffusion. The effective diffusion constants associated with this effect are proportional to the spacestep size. proportional to the spacestep size. Introduction In a previous paper we presented a system of differential equations that can be used to model oil recovery by chemical flooding. The general system allows for an arbitrary number of components as well as an arbitrary number of phases in an isothermal system. For a binary, two-phase system, the equations reduced to those of the Buckley-Leverett theory under the usual assumptions of incompressibility and each phase containing only a single component, as well as in the more general case where both phases have significant concentrations of both components, but the phases are incompressible and the concentration in one phase is a very weak function of the pressure of the other phase at a given temperature. pressure of the other phase at a given temperature. For a ternary, two-phase system a set of three differential equations was obtained. These equations are applicable to chemical flooding with surfactant, polymer, etc. In this paper, we present a numerical solution to these equations paper, we present a numerical solution to these equations for I D flow in the absence of gravity. Our purpose is to develop a model that includes the physical phenomena influencing oil displacement by surfactant systems and bridges the gap between laboratory displacement tests and reservoir simulation. It also should be of value in defining experiments to elucidate the mechanisms involved in oil displacement by surfactant systems and ultimately reduce the number of experiments necessary to optimize a given surfactant system.

Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs

2021 ◽  
Author(s):  
Nancy Chun Zhou ◽  
Meng Lu ◽  
Fuchen Liu ◽  
Wenhong Li ◽  
Jianshen Li ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Aqueous Solubility ◽  
Low Permeability ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Key Factors ◽  
Low Salinity ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.

A Temperature Operating Window Concept for Application of Nonionic Surfactants for EOR in Unconventional Shale Reservoirs

2021 ◽  
Author(s):  
I Wayan Rakananda Saputra ◽  
David S. Schechter
Keyword(s):  
Crude Oil ◽  
Nonionic Surfactant ◽  
Cloud Point ◽  
Oil Recovery ◽  
Nonionic Surfactants ◽  
Spontaneous Imbibition ◽  
Reservoir Temperature ◽  
Rock System ◽  
Temperature Operating ◽  
Operating Window

Abstract Surfactant performance is a function of its hydrophobic tail, and hydrophilic head in combination with crude oil composition, brine salinity, rock composition, and reservoir temperature. Specifically, for nonionic surfactants, temperature is a dominant variable due to the nature of the ethylene oxide (EO) groups in the hydrophilic head known as the cloud point temperature. This study aims to highlight the existence of temperature operating window for nonionic surfactants to optimize oil recovery during EOR applications in unconventional reservoirs. Two nonylphenol (NP) ethoxylated nonionic surfactants with different EO head groups were investigated in this study. A medium and light grade crude oil were utilized for this study. Core plugs from a carbonate-rich outcrop and a quartz-rich outcrop were used for imbibition experiments. Interfacial tension and contact angle measurements were performed to investigate the effect of temperature on the surfactant interaction in an oil/brine and oil/brine/rock system respectively. Finally, a series of spontaneous imbibition experiments was performed on three temperatures selected based on the cloud point of each surfactant in order to construct a temperature operating window for each surfactant. Both nonionic surfactants were observed to improve oil recovery from the two oil-wet oil/rock system tested in this study. The improvement was observed on both final recovery and rate of spontaneous imbibition. However, it was observed that each nonionic surfactant has its optimum temperature operating window relative to the cloud point of that surfactant. For both nonionic surfactants tested in this study, this window begins from the cloud point of the surfactant up to 25°F above the cloud point. Below this operating window, the surfactant showed subpar performance in increasing oil recovery. This behavior is caused by the thermodynamic equilibrium of the surfactant at this temperature which drives the molecule to be more soluble in the aqueous-phase as opposed to partitioning at the interface. Above the operating window, surfactant performance was also inferior. Although for this condition, the behavior is caused by the preference of the surfactant molecule to be in the oleic-phase rather than the aqueous-phase. One important conclusion is the surfactant achieved its optimum performance when it positions itself on the oil/water interface, and this configuration is achieved when the temperature of the system is in the operating window mentioned above. Additionally, it was also observed that the 25°F operating window varies based on the characteristic of the crude oil. A surfactant study is generally performed on a single basin, with a single crude oil on a single reservoir temperature or even on a proxy model at room temperature. This study aims to highlight the importance of applying the correct reservoir temperature when investigating nonionic surfactant behavior. Furthermore, this study aims to introduce a temperature operating window concept for nonionic surfactants. This work demonstrates that there is not a "one size fits all" surfactant design.

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