scholarly journals Adsorption of Surface Active Ionic Liquids on Different Rock Types under High Salinity Conditions

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
Shilpa Kulbhushan Nandwani ◽  
Mousumi Chakraborty ◽  
Smita Gupta
Keyword(s):  
Ionic Liquids ◽  
Adsorption Isotherm ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Adsorption Mechanism ◽  
High Salinity ◽  
Reservoir Rock ◽  
Rock Surface ◽  
Rock Types ◽  
Surface Active

Abstract A new class of surface active ionic liquids (SAIL) have been reported to be a greener alternative to the conventional surfactants in enhanced oil recovery (EOR). These SAILs work efficiently under harsh salinity conditions encountered in the reservoir thereby recovering more additional oil during the tertiary oil recovery process. Adsorption mechanism of SAILs on different rock surface is however, not yet reported in the literature. This article highlights adsorption mechanism of three cationic SAILs having different headgroups, viz., imidazolium, pyridinium, pyrrolidinium, on different rock surfaces (crushed natural carbonate rock and crushed sandstone rock). All the SAILs studied here however had the same tail length and same anion (Br−) attached to it. XRD and XPS characterization techniques reveal that the crushed natural carbonate rock contains a substantial amount of silica, thus rendering it a slight negative charge. Static adsorption tests show that the retention efficiency on the natural carbonate type of rock for all the SAILs was lower than the conventional cationic surfactant, CTAB. The adsorption data obtained thereby was examined using four different adsorption isotherm models (Langmuir, Freundlich, Redlich-Peterson, and Sips). Results suggest that Sips adsorption isotherm model can satisfactorily estimate the adsorption of all the surface active agents on the natural carbonate rock. Factors like mineralogical composition of rock surface, presence of divalents, temperature, and structure of surfactants strongly affect the amount of surfactant adsorbed on reservoir rock. In order to evaluate the simultaneous effect all these factors as well as their interdependence on the retention capability of the three SAILs, a design of experiments approach has been employed further in this study. Statistical analysis of the data obtained after performing the full factorial experiments reveal that at high salinity, imidazoluim based SAIL show minimal adsorption on crushed natural carbonate rock at higher temperature. In general, at a given ionic strength, with increasing temperature as the amount of divalent in the aqueous solution increases, the amount of SAIL adsorbed on both the rock types decreases. Electrostatic attraction is the basic mechanism in governing adsorption of SAILs on the two types of rock surfaces. Results presented in this work can be used for EOR schemes.

Enhancing hydrocarbon productivity via wettability alteration: a review on the application of nanoparticles

2019 ◽  
Vol 35 (4) ◽  
pp. 531-563 ◽  
Author(s):  
Asefe Mousavi Moghadam ◽  
Mahsa Baghban Salehi
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Review Paper ◽  
Oil And Gas Industry ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Main Element ◽  
Preparation Methods ◽  
Hydrocarbon Production ◽  
Rock Types

AbstractWettability alteration (WA) of reservoir rock is an attractive topic in the upstream oil and gas industry, for the improvement of hydrocarbon production. Novel methods and chemicals that may change the wetting state of reservoir rock to water-wet have highly attracted petroleum researchers’ attention. Use of nanoparticles might be matured enough in different branches of sciences but in WA is still young, which increased in recent decades. This review paper presents a comprehensive review on WA, especially in terms of nanoparticle application in increasing oil recovery. Therefore, the areas of controversy of two rock types (carbonate and sandstone) as a main element in WA are discussed. A selection of reviewed nanoparticle types, preparation methods, and effective factors was also investigated. Moreover, two main methods of WA, static and dynamic, are highlighted. Although these methods have been discussed in many reviews, a clear classification form of these has not been considered. Such comprehensive arrangement is presented in this review, specifically on nanoparticle application. Moreover, coreflooding tests of different fluid types and injection scenarios are discussed. The review indicates promising use of nanoparticles in increasing ultimate oil recovery. It was hoped the current review paper can provide useful related reference to study WA via nanoparticle application.

A Pore-Network-Modeling Approach To Predict Petrophysical Properties of Diatomaceous Reservoir Rock

2007 ◽  
Vol 10 (06) ◽  
pp. 597-608 ◽  
Author(s):  
Liping Jia ◽  
Cynthia Marie Ross ◽  
Anthony Robert Kovscek
Keyword(s):  
Multiphase Flow ◽  
Capillary Pressure ◽  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Pore Network ◽  
Reservoir Rock ◽  
Pore Network Model ◽  
Rock Types ◽  
Capillary Pressure Curves

Summary A 3D pore-network model of two-phase flow was developed to compute permeability, relative permeability, and capillary pressure curves from pore-type, -size, and -shape information measured by means of high-resolution image analysis of diatomaceous-reservoir-rock samples. The diatomite model is constructed using pore-type proportions obtained from image analysis of epoxy-impregnated polished samples and mercury-injection capillary pressure curves for diatomite cores. Multiple pore types are measured, and each pore type has a unique pore-size and throat-size distribution that is incorporated in the model. Network results present acceptable agreement when compared to experimental measurements of relative permeability. The pore-network model is applicable to both drainage and imbibition within diatomaceous reservoir rock. Correlation of network-model results to well log data is discussed, thereby interpolating limited experimental results across the entire reservoir column. Importantly, our method has potential to predict the petrophysical properties for reservoir rocks with either limited core material or those for which conventional experimental measurements are difficult, unsuitable, or expensive. Introduction Model generation for reservoir simulation requires accurate entering of physical properties such as porosity, permeability, initial water saturation, residual-oil saturation, capillary pressure functions, and relative permeability curves. These functions and parameters are necessary to estimate production rate and ultimate oil recovery, and thereby optimize reservoir development. Accurate measurement and representation of such information is, therefore, essential for reservoir modeling. Relative permeability and capillary pressure curves are the most important constitutive relations to represent multiphase flow. Often, it is difficult to sample experimentally the range of relevant multiphase-flow behavior of a reservoir. In addition to the availability of rock samples, measurements are frequently time consuming to conduct, and conventional techniques are not suitable for all rock types (Schembre and Kovscek 2003). It is impossible, therefore, to measure all the unique relative permeability functions of different reservoir-rock types and variations within a rock type. This lack of constitutive information limits the accuracy of reservoir simulators to predict oil recovery. Simply put, other available data must be queried for their relevance to multiphase flow and must be used to interpret the available relative permeability and capillary pressure information.

Adsorption/Retention of Petroleum Sulfonates in Berea Cores

1977 ◽  
Vol 17 (05) ◽  
pp. 353-357 ◽  
Author(s):  
J.H. Bae ◽  
C.B. Petrick
Keyword(s):  
Adsorption Isotherm ◽  
Aqueous Solutions ◽  
Flow Rate ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Equivalent Weight ◽  
Flow Rates ◽  
The Core ◽  
Petroleum Sulfonate ◽  
Pass Through

Abstract A series of petroleum sulfonate adsorption experiments was conducted in 2-in.-diameter, 2-ft-long Berea cores initially saturated with 1-percent NaCl brine. The sulfonates used had an average equivalent weight of 430 with a broad equivalent-weight distribution. The concentration ranged from 0.01 to 8 per cent. The flow rates investigated ranged from 2 to 36 ft/D. Adsorption was determined either from analysis of the effluent concentrations or by extraction of sulfonates from the core. The physical properties of the solutions were also measured. In several tests, Na2CO3 was used as a sacrificial chemical, either in a preflood or added to the sulfonate solution. It was found that at certain concentrations, apparent adsorption is dependent on the flow rate. The sulfonate adsorption isotherm was found to pass through a maximum. The value of the pass through a maximum. The value of the adsorption maximum and the concentration at which it occurs are also dependent on the flow rate. The time required for adsorption equilibrium was found to increase with increasing sulfonate concentration. A sacrificial chemical reduced the sulfonate adsorption. However, sulfonate adsorption increased gradually with time. Adsorption tests should be conducted at realistic flow rates. Introduction One of the major problems in surfactant flooding is the adsorption of surfactants on the reservoir rock. If adsorption is excessive, surfactants are depleted rapidly from the slug as it moves through the reservoir; consequently, it loses the ability to lower the oil-water interfacial tension. Thus, the magnitude of adsorption is an important technical as well as economic parameter. It has been reported that the adsorption of petroleum sulfonates is selective. The high-equivalent-weight sulfonates are adsorbed preferentially whole low-equivalent-weight preferentially whole low-equivalent-weight sulfonates show almost no adsorption. Most of the adsorbed sulfonates had an equivalent weight of 500 or more. This type of fractionation was considered to be the main cause for poor oil recovery in a field pilot test. The literature data on the adsorption of petroleum sulfonates from aqueous solutions indicate petroleum sulfonates from aqueous solutions indicate that there is a maximum in the adsorption isotherm. Furthermore, the adsorption of sulfonate is reduced significantly when sacrificial chemicals are used. The experimental methods used in these measurements differ from one another and, on occasion, the adsorbed sulfonates are defined to be the amount extracted by a solvent after a brine flush. The term "adsorption" is used here rather loosely. Some people prefer the term retention to adsorption since there may be physical retention in a core. The physical retention may or may not exist in a given experiment and detection of it may be very difficult. The objective of this work is to investigate the adsorption phenomenon in dynamic core tests. Several questions are examined: How is the adsorption isotherm related to the general properties of the solution? Do the dynamic test conditions affect the adsorption measurement? Are sacrificial chemicals useful in reducing sulfonate adsorption? EXPERIMENTAL PROCEDURES The petroleum sulfonate used was a blend of sulfonates, TRS 18 and TRS 40 obtained from Witco Chemical Co., and has an average equivalent weight of 430. The equivalent weight ranged from 250 to 650, with about 80 percent ranging from 350 to 550, almost evenly distributed. Isopropyl alcohol was used as a cosolvent at 1/10 of the sulfonate concentration. A 1-percent NaCl brine was used as the aqueous medium. Weight percentage is used throughout this paper. All adsorption tests were conducted at room temperature of 72 degrees F in 2-in.-diameter, 2-ft-long Berea cores saturated with brine. The permeability to brine in all tests was 450 + 25 md. The sulfonate solution was injected continuously into the cores using a positive-displacement pump. The produced fluids were collected in a fraction collector. In most cases, at the end of sulfonate injection, the sulfonate in the core was extracted immediately with a methanol-chloroform mixture. SPEJ P. 353

scholarly journals Scrutinizing Self-Assembly, Surface Activity and Aggregation Behavior of Mixtures of Imidazolium Based Ionic Liquids and Surfactants: A Comprehensive Review

2021 ◽  
Vol 9 ◽  
Author(s):  
Harsh Kumar ◽  
Gagandeep Kaur
Keyword(s):  
Ionic Liquids ◽  
Surface Activity ◽  
Oil Recovery ◽  
Self Assembly ◽  
Carbon Capture ◽  
Aggregation Behavior ◽  
The Self ◽  
Mixed Micellization ◽  
Treatment Technologies ◽  
Surface Active

The desire of improving various processes like enhanced oil recovery (EOR), water treatment technologies, biomass extraction, organic synthesis, carbon capture etc. in which conventional surfactants have been traditionally utilized; prompted various researchers to explore the self-assembly and aggregation behavior of different kinds of surface-active molecules. Ionic liquids (ILs) with long alkyl chain present in their structure constitute the advantageous properties of surfactant and ILs, hence termed as surface-active ionic liquids (SAILs). The addition of ILs and SAILs significantly influence the surface-activity and aggregation behavior of industrially useful conventional surfactants. After a brief review of ILs, SAILs and surfactants, the prime focus is made on analyzing the self-assembly of SAILs and the mixed micellization behavior of conventional surfactants with different ILs.

A Chemical Theory for Linear Alkaline Flooding

1982 ◽  
Vol 22 (02) ◽  
pp. 245-258 ◽  
Author(s):  
E.F. deZabala ◽  
J.M. Vislocky ◽  
E. Rubin ◽  
C.J. Radke
Keyword(s):  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Acid Number ◽  
Reservoir Rock ◽  
Crude Oils ◽  
Fractional Flow ◽  
Surface Active ◽  
Displacement Model

Abstract A simple equilibrium chemical model is presented for continuous, linear, alkaline waterflooding of acid oils. The unique feature of the theory is that the chemistry of the acid hydrolysis to produce surfactants is included, but only for a single acid species. The in-situ produced surfactant is presumed to alter the oil/water fractional flow curves depending on its local concentration. Alkali adsorption lag is accounted for by base ion exchange with the reservoir rock. The effect of varying acid number, mobility ratio, and injected pH is investigated for secondary and tertiary alkaline flooding. Since the surface-active agent is produced in-situ, a continuous alkaline flood behaves similar to a displacement with a surfactant pulse. This surfactant-pulse behavior strands otherwise mobile oil. It also leads to delayed and reduced enhanced oil recovery for adverse mobility ratios, especially in the tertiary mode. Caustic ion exchange significantly delays enhanced oil production at low injected pH. New, experimental tertiary caustic displacements are presented for Ranger-zone oil in Wilmington sands. Tertiary oil recovery is observed once mobility control is established. Qualitative agreement is found between the chemical displacement model and the experimental displacement results. Introduction Use of alkaline agents to enhance oil recovery has considerable economic impetus. Hence, significant effort has been directed toward understanding and applying the process. To date, however, little progress has been made toward quantifying the alkaline flooding technique with a chemical displacement model. Part of the reason why simulation models have not been forthcoming for alkali recovery schemes is the wide divergence of opinion on the governing principles. Currently, there are at least eight postulated recovery mechanisms. As classified by Johnson and Radke and Somerton, these include emulsification with entrainment, emulsification with entrapment, emulsification (i.e., spontaneous or shear induced) with coalescence, wettability reversal (i.e., oil-wet to water-wet or water-wet to oil-wet), wettability gradients, oil-phase swelling (i.e., from water-in-oil emulsions), disruption of rigid films, and low interfacial tensions. The contradictions among these mechanisms apparently reside in the chemical sensitivity of the crude oil and the reservoir rock to reaction with hydroxide. Different crude oils in different reservoir rock can lead to widely disparate behavior upon contact with alkali under varying environments such as temperature, salinity, hardness concentration, and pH. The alkaline process remains one of the most complicated and least understood. It is not surprising that there is no consensus on how to design a high-pH flood for successful oil recovery. One theme, however, does unify all present understanding. The crude oil must contain acidic components, so that a finite acid number (i.e., the milligrams of potassium hydroxide required to neutralize 1 gram of oil) is necessary. Acid species in the oil react with hydroxide to produce salts, which must be surface active. It is not alkali per se that enhances oil recovery, but rather the hydrolyzed surfactant products. Therefore, a high acid number is not a sufficient recovery criterion, because not all the hydrolyzed acid species will be interfacially active. That acid crude oils can produce surfactants upon contact with alkali is well documented. The alkali technique must be distinguished from all others by the fundamental basis that the chemicals promoting oil recovery are generated in situ by saponification. SPEJ P. 245^

Numerical Modeling of the Behaviors of Sacrificial Polymers on Reducing Surfactant Loss

2020 ◽  
Vol 142 (9) ◽  
Author(s):  
Erxiu Shi ◽  
David Cure ◽  
Yin Feng ◽  
Hao Ying
Keyword(s):  
Mathematical Model ◽  
Oil Recovery ◽  
Laboratory Data ◽  
Iterative Solution ◽  
Reservoir Rock ◽  
Rock Surface ◽  
Competitive Behavior ◽  
Kutta Method ◽  
Runge Kutta Method ◽  
Actual Field

Abstract The use of surfactants to alter the reservoir hydrocarbons affinity toward the injection fluids is an effective method to improve oil recovery for depleted reservoirs. However, the actual field applications of this technique are limited by economical complications such as the loss of surfactants in the reservoir rock pores. Reducing the adsorption of surfactants to the reservoir rock can be achieved through adding sacrificial agents to the injection slug. These sacrificial agents such as polymers can engage in a competitive behavior with surfactants for the adsorption on the reservoir rock surface. In this paper, a mathematical model that accounts for the interactive behaviors (adsorption and desorption) among multispecies nanoparticles in porous media was developed and validated by comparing with laboratory data to demonstrate its capability in solving adsorptive behaviors between surfactant and sacrificial polymers. An iterative solution associated with the presented model was verified by the fourth-order Runge–Kutta method to prove its correctness in simulations. Three groups of computational experiments were designed, and four operational scenarios were analyzed for each group to compare various injection plans and investigate the effect of desorption rates of sacrificial polymers on relieving the loss of surfactant. Finally, the 1D solution was integrated into an in-house streamline simulator that indicates its compatibility to be integrated into streamline-based simulation procedures and its potential in solving for more complex 3D heterogeneous problems.

Effect of Microcellulose on Wettability of Reservoir Rock Surface Model

2019 ◽  
Vol 811 ◽  
pp. 55-61
Author(s):  
Mia Ledyastuti ◽  
Galuh Sukmarani
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Contact Angle Measurement ◽  
Angle Measurement ◽  
Reservoir Rock ◽  
Rock Surface ◽  
Surface Model ◽  
Particle Sizes ◽  
Produce Water ◽  
The Difference

Wettability is one factor that influences the enhanced oil recovery. Water-wet surfaces are predicted increasing the oil recovery from the reservoir. Microcellulose has the potential to produce water-wet surfaces. In this experiment, two types of microcellulose were used with different particle sizes of 2.9 μm and 14 μm. Both types of microcellulose are then applied to the reservoir rock surface model, i.e the surface of bentonite which has been soaked in crude oil for one week at 60 °C. Contact angle measurement shows that there is a decrease in water-the reservoir rock surface model contact angle from ~ 90 ° to ~ 80 ° when applied microcellulose solution 0.5% w/w. The difference in microcellulose size causes a difference in contact angle of about 5° at microcellulose solution 2.5%. This shows the application of microcellulose on the reservoir rock surface model causing the surface to be more water-wet.

Investigation of Oil Presence and Wettability Restoration Effects on Sulfonated Polymer Retention in Carbonates Under Harsh Conditions

2021 ◽  
Author(s):  
Umar Alfazazi ◽  
Nithin Chacko Thomas ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Careful Consideration ◽  
Rock Surface ◽  
Ct Scanner ◽  
Core Samples ◽  
The Impact ◽  
Polymer Retention ◽  
Harsh Conditions

Abstract Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effect of oil presence and wettability restoration on polymer retention under harsh reservoir conditions of high temperature and high salinity (HTHS). An ATBS-based polymer was used for this study. Polymer single- and two-phase dynamic retention tests as well as bulk- and in-situ rheological experiments were conducted on Indiana limestone outcrops and in the presence of high salinity brine of 243,000 ppm at temperature of 50 °C. A total of four coreflooding experiments were conducted on core samples with similar petrophysical properties. Bulk rheology tests showed that the polymer is stable at HTHS conditions. Also, polymer retention and in-situ rheology tests highlighted the significance of oil presence in the core samples where retention was found to be around 40-50 and 25-30 μg/g-rock in the absence and presence of oil, respectively. An additional 50% reduction in retention was further observed on a restored wettability (aged) core sample. Polymer inaccessible pore volume (IPV) was found to be high in the range of 23 to 28%, which was supported by the 1D saturation profiles obtained from the CT scanner. The ATBS-based polymer shows excellent results for applications in carbonates under harsh conditions without considerable polymer loss or plugging. This paper also provides valuable insights into the impact of oil presence and wettability restoration on polymer retention. Furthermore, this study shows that careful consideration of the latter factor is necessary to avoid unrepresentative and inflated polymer retention values in oil reservoirs.

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