Role of Intermolecular Forces on Surfactant-Steam Performance into Heavy Oil Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-6
Author(s):  
Lee Yeh Seng ◽  
Berna Hascakir
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Intermolecular Forces ◽  
Immiscible Fluids ◽  
Reservoir Rock ◽  
Crude Oils ◽  
Head Group ◽  
Polar Head Group ◽  
Polar Head

Summary This study investigates the role of polar fractions of heavy oil in the surfactant-steamflooding process. Performance analyses of this process were done by examination of the dipole-dipole and ion-ion interactions between the polar head group of surfactants and the charged polar fraction of crude oil, namely, asphaltenes. Surfactants are designed to reduce the interfacial tension (IFT) between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the IFT by aligning themselves at the interface of these two immiscible fluids; this way, their polar head group can stay in water and nonpolar tail can stay in the oil phase. However, in heavy oil, the crude oil itself has a high number of polar components (mainly asphaltenes). Moreover, the polar head group in surfactants is charged, and the asphaltene fraction of crude oils carries reservoir rock components with charges. The impact of these intermolecular forces on the surfactant-steam process performance was investigated with 10 coreflood experiments on an extraheavy crude oil. Nine surfactants (three anionic, three cationic, and three nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltene fractions of produced oil and residual oil samples. The differences in each group of surfactants tested in this study are the tail length. Results indicate that a longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of anionic surfactants resulted in higher oil recovery. Further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil, giving higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on the polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltene surface charges were becoming lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with the polar head of surfactants, then the recovery rate increases. Our study shows that the surfactant-steamflooding performance in heavy oil reservoirs is controlled by the interaction between asphaltenes and the polar head group of surfactants. Accordingly, the main mechanism that controls the effectiveness of the process is the ion-ion interaction between the charges in asphaltene surfaces and the polar head group of crude oils. Because crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.

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^

Effect of Oil Composition on Miscible-Type Displacement by Carbon Dioxide

1982 ◽  
Vol 22 (01) ◽  
pp. 87-98 ◽  
Author(s):  
LeRoy W. Holm ◽  
Virgil A. Josendal
Keyword(s):  
Carbon Dioxide ◽  
Crude Oil ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Crude Oils ◽  
Co2 Flooding ◽  
Oil Composition ◽  
Extraction Mechanism ◽  
Minimum Miscibility Pressure ◽  
Displacement Front

Abstract This paper presents additional data related to the correlation between minimum miscibility pressure (MMP) for CO2 flooding and to the composition of the crude oil to be displaced. Yellig and Metcalfe have stated that there is little or no effect of oil composition on the MMP. However, their conclusion was based on experiments with one type of reservoir oil that was varied in C through C6 content and in the amount of C7 + present but not varied in composition of the C7 + fraction. We have found that the Holm-Josendal correlation, which is based on temperature and C5 + molecular weight, predicts the general trend of the MMP's required for CO2 flooding of various crude oils. MMP's were predicted with this correlation and then tested for several crude oils using oil recovery of 80% at CO2 break through and 94% ultimate recovery as the criteria. We now have data showing that miscible-type displacement is also correlatable with the amount of C5 through C3O hydrocarbons present in the crude oil and with the solvency of the CO2 as indicated by its density. Variations from such a correlation are shown to be related to the C5 through C 12 content and to the type of these hydrocarbons. The MMP data were obtained from slim-tube floods with crude oils having gravities between 28 and 44 degrees API (0.88 and 0.80 g/cm3) and C5 + molecular weights between 171 and 267. The crude oils used varied in carbon residue between 1 and 4 wt% and in waxy hydrocarbon content between 1 and 17%. The required MMP for these crude oils at 165 degrees F (74 degrees C) varied between 2,450 and 4,400 psi (16.9 and 30.3 MPa) for an oil recovery of 94% OIP. The MMP was found to be a linear function of the amount of C5 through C30 hydrocarbons present and of the density of the CO2. Introduction Our 1974 paper, "Mechanisms of Oil Displacement by Carbon Dioxide," discussed the various mechanisms by which oil is displaced from reservoir rock using CO2. One conclusion of this study was that multiple-contact, miscible-type displacement of oil occurs through extraction of C5 through C30 hydrocarbons from the reservoir oil by COB when a certain pressure is maintained at a given flood temperature. The mechanism of oil recovery was described as follows. The CO2 vaporizes or extracts hydrocarbons from the reservoir oil until a sufficient quantity of these hydrocarbons exists at the displacement front to cause the oil to be miscibly displaced. At that point, the vaporization or extraction mechanism stops until the miscible front that has been developed breaks down through the dispersion mechanism. When miscibility does not exist, the vaporization or extraction mechanism again occurs to re-establish miscibility. The miscible bank is formed, dispersed, and reformed throughout the displacement path; a small amount of residual oil remains behind all along the displacement path. Also, an optimal flooding pressure at a given temperature for a given oil was defined in that paper as when oil recovery of about 94% OIP was achieved and above which point essentially no additional oil was recovered. This pressure has since been termed the "minimum miscibility pressure" by others. We further determined in our previous study thatthis miscible-type displacement does not depend on the presence of C2 through C4 in the reservoir oil and thatthe presence of methane in the reservoir oil does not change the MMP appreciably. Those findings have been confirmed by Yellig and Metcalfe with the qualification that the CO2 MMP must be greater than or equal to the bubble-point pressure of the reservoir oil. SPEJ P. 87^

Industrial Application of Nickel Tallate Catalyst During Cyclic Steam Stimulation in Boca De Jaruco Reservoir

2021 ◽  
Author(s):  
Alexey V. Vakhin ◽  
Irek I. Mukhamatdinov ◽  
Firdavs A. Aliev ◽  
Dmitriy F. Feoktistov ◽  
Sergey A. Sitnov ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Industrial Application ◽  
Laboratory Scale ◽  
Catalyst Precursor ◽  
Hydrothermal Conditions ◽  
Cyclic Steam Stimulation ◽  
Steam Stimulation

Abstract A nickel-based catalyst precursor has been synthesized for in-situ upgrading of heavy crude oil that is capable of increasing the efficiency of steam stimulation techniques. The precursor activation occurs due to the decomposition of nickel tallate under hydrothermal conditions. The aim of this study is to analyze the efficiency of in-situ catalytic upgrading of heavy oil from laboratory scale experiments to the field-scale implementation in Boca de Jaruco reservoir. The proposed catalytic composition for in-reservoir chemical transformation of heavy oil and natural bitumen is composed of oil-soluble nickel compound and organic hydrogen donor solvent. The nickel-based catalytic composition in laboratory-scale hydrothermal conditions at 300°С and 90 bars demonstrated a high performance; the content of asphaltenes was reduced from 22% to 7 wt.%. The viscosity of crude oil was also reduced by three times. The technology for industrial-scale production of catalyst precursor was designed and the first pilot batch with a mass of 12 ton was achieved. A «Cyclic steam stimulation» technology was modified in order to deliver the catalytic composition to the pay zones of Boca de Jaruco reservoir (Cuba). The active forms of catalyst precursors are nanodispersed mixed oxides and sulfides of nickel. The pilot test of catalyst injection was carried out in bituminous carbonate formation M, in Boca de Jaruco reservoir (Cuba). The application of catalytic composition provided increase in cumulative oil production and incremental oil recovery in contrast to the previous cycle (without catalyst) is 170% up to date (the effect is in progress). After injection of catalysts, more than 200 samples from production well were analyzed in laboratory. Based on the physical and chemical properties of investigated samples and considering the excellent oil recovery coefficient it is decided to expand the industrial application of catalysts in the given reservoir. The project is scheduled on the fourth quarter of 2021.

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

2021 ◽  
Author(s):  
Ali Reham Al-Jabri ◽  
Rouhollah Farajzadeh ◽  
Abdullah Alkindi ◽  
Rifaat Al-Mjeni ◽  
David Rousseau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Field ◽  
Reservoir Rock ◽  
Sultanate Of Oman ◽  
Industrial Chemicals ◽  
Oil Viscosity ◽  
Injection Strategy ◽  
Operational Conditions

Abstract Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.

The effect of polar head group of dodecyl surfactants on the growth of wheat and cucumber

Chemosphere ◽  
2020 ◽  
Vol 254 ◽  
pp. 126918
Author(s):  
Aleksandar Tot ◽  
Ivana Maksimović ◽  
Marina Putnik-Delić ◽  
Milena Daničić ◽  
Slobodan Gadžurić ◽  
...  
Keyword(s):  
Head Group ◽  
Polar Head Group ◽  
Polar Head

Glycosylinositol phosphoceramide-specific phospholipase D activity catalyzes transphosphatidylation

2019 ◽  
Vol 166 (5) ◽  
pp. 441-448 ◽  
Author(s):  
Rumana Yesmin Hasi ◽  
Makoto Miyagi ◽  
Katsuya Morito ◽  
Toshiki Ishikawa ◽  
Maki Kawai-Yamada ◽  
...  
Keyword(s):  
Chain Length ◽  
Phospholipase D ◽  
Secondary Alcohol ◽  
Primary Alcohol ◽  
Tertiary Alcohol ◽  
Head Group ◽  
Polar Head Group ◽  
Polar Head ◽  
A Chain ◽  
Sugar Chains

Abstract Glycosylinositol phosphoceramide (GIPC) is the most abundant sphingolipid in plants and fungi. Recently, we detected GIPC-specific phospholipase D (GIPC-PLD) activity in plants. Here, we found that GIPC-PLD activity in young cabbage leaves catalyzes transphosphatidylation. The available alcohol for this reaction is a primary alcohol with a chain length below C4. Neither secondary alcohol, tertiary alcohol, choline, serine nor glycerol serves as an acceptor for transphosphatidylation of GIPC-PLD. We also found that cabbage GIPC-PLD prefers GIPC containing two sugars. Neither inositol phosphoceramide, mannosylinositol phosphoceramide nor GIPC with three sugar chains served as substrate. GIPC-PLD will become a useful catalyst for modification of polar head group of sphingophospholipid.

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