Acid Number Measurements Revisited

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 496-500 ◽  
Author(s):  
Tianguang Fan ◽  
Jill S. Buckley
Keyword(s):  
Stearic Acid ◽  
Crude Oil ◽  
Acid Number ◽  
Crude Oils ◽  
Chemical Recovery ◽  
Base Number ◽  
Oil Composition ◽  
Recovery Processes ◽  
Astm Method ◽  
Titration Endpoint

Summary We propose an improved procedure for measuring acid numbers. Major changes include spiking crude oil samples and blank solutions with a known amount of stearic acid to force a clear titration endpoint, replacing potassium hydroxide with tetrabutyl ammonium hydroxide in the alcoholic titratant, and correctly accounting for changes in electrode response that occur upon exposure of the electrode to crude oil. Introduction Chemical methods of improved oil recovery are not equally effective in all reservoirs. An important factor that can influence a project's success is crude oil composition. Because crude oils are complex mixtures, evaluation of oil composition in a way that is meaningful with respect to specific chemical recovery processes can present many problems. In particular, there is a need for improvements in acid number (AN) measurements, also known as total acid number (TAN). AN is important in evaluating crude oils for alkaline and surfactant processes, but in order to be useful, measurements must be comparable from one laboratory to another and must also capture chemically meaningful information about the crude oil. Standardization (e.g., the current ASTM recommended procedure) should assist with the first requirement: that different labs be able to reproduce the AN value within some reasonable tolerance. Standardization does not, however, ensure that the measurement captures information about a crude oil that can be used to predict its interactions in chemical recovery processes. AN measurements are used to characterize an oil with respect to total concentration of strong and weak acids by means of nonaqueous potentiometric titration. The standard procedure (ASTM 2001) is designed to measure ANs in the range of 0.05 to 250 mg KOH/g oil. Stock-tank samples of crude oil usually have ANs that are at the low end of this range; strong acids are not encountered. Thus the sensitivity of the ASTM method is barely adequate for many samples of interest. According to the ASTM procedure, 20 g of oil should be used if AN is less than 1 mg KOH/g oil. Unfortunately, high-quality samples of crude oil are expensive to obtain and the quantity is very limited. Using 20 g for AN measurement would often preclude making any other measurements. The usefulness of AN data is greatly increased if it forms part of a matrix of information that includes, at a minimum, base number (BN), SARA fraction data, and information about asphaltene stability. There are few, if any, interfacial phenomena that correlate exclusively to AN. Basic constituents of an oil can also be assessed by nonaqueous potentiometric titration, but endpoints are often more difficult to detect because the organic bases that occur in crude oils can have a wide range of dissociation constants. More than a decade ago, Dubey and Doe (1993) published recommendations for improved base number measurements by adding a known amount of quinoline to force a readily detectible titration endpoint. Base numbers measured using spiked oil samples were significantly higher than those measured by the ASTM method and the higher base numbers were shown to correlate, together with AN for the same oils, with observations of wetting reversal on silica surfaces. A similar procedure was shown to improve the precision of AN titrations using stearic acid as the spiking agent for routine AN measurements (Monsterleet and Buckley 1996). Precipitated material was observed for some crude oils in the standard solvent (50% toluene, 49.5% isopropanol or IPA, and 0.5% water). Stearic acid and o-nitrophenol were used as spiking agents by Zheng and Powers (2003).

A Study of Caustic Solution-Crude Oil Interfacial Tensions

1975 ◽  
Vol 15 (03) ◽  
pp. 197-202 ◽  
Author(s):  
Harley Y. Jenning
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Sodium Hydroxide ◽  
Surface Activity ◽  
Acid Number ◽  
Caustic Solution ◽  
Crude Oils ◽  
Interfacial Tensions ◽  
Drop Method ◽  
Pendent Drop

Abstract This paper presents the results of a study of caustic solution-crude oil interfacial tension measurements on 164 crude oils from 78 fields. Of these crude oils 131 showed marked surface activity against caustic solutions. Surface activity of crude oil against caustic solution correlates with the acid number, gravity, and viscosity. Almost all crude oils with gravities of 20 degrees API or lower produced a caustic solution-crude oil interfacial produced a caustic solution-crude oil interfacial tension less than 0.01 dyne/cm. Of the interfacially active samples, 90 percent reached maximum measurable surface activity at a caustic concentration of close to 0.1 percent by weight. The dissolved solids content of the water bas a marked influence on the surface activity. Sodium chloride in solution reduces the caustic concentration required to give maximum surface activity. Conversely, calcium chloride in solution suppresses surface activity. Introduction The oil-production technology literature contains a number of papers that indicate that the addition of sodium hydroxide to the flood water beneficially affects oil recovery. Although the proposed recovery mechanisms differ in detail, a variable common to almost all is the interfacial tension between caustic solutions and crude oil. A study of the factors influencing caustic solution-crude oil interfacial tensions is fundamental to an understanding of the proposed mechanisms and their optimum utilization. proposed mechanisms and their optimum utilization. We have obtained interfacial tensions against caustic solutions of 164 crudes. These crudes come from all major oil-producing areas in the free world. In addition to determining the correlation of interfacial tension with crude oil properties of acid number, gravity, and viscosity, we have also determined the effect of certain dissolved solids in the water. We define acid number as the number of milligrams of potassium hydroxide required to neutralize the acid in one gram of sample. The interfacial tension data were obtained by the pendent-drop method. pendent-drop method. EXPERIMENTAL PROCEDURE The caustic solutions used in this study were prepared by adding reagent-grade sodium hydroxide prepared by adding reagent-grade sodium hydroxide to laboratory distilled water. Our standard solutions were made from a 50 percent by weight reagent-grade sodium hydroxide solution. For convenience in relating our laboratory data to possible field application, the data were recorded and plotted in terms of weight percent sodium hydroxide. The pH of the caustic solutions was determined experimentally using a Coming expanded-scale pH meter; and the densities of the caustic solutions were measured experimentally using a Chainomatic Westphal balance. CRUDE OILS The crude oils were protected from the atmosphere and were collected in carefully cleaned glass or, when practicable, in plastic-lined containers. The crude oil samples were free of chemical additives, such as emulsion breakers and corrosion inhibitors. If the oil contained suspended solid material it was dehydrated and filtered. The densities were determined by the Westphal balance; and the viscosities were determined as a function of temperature using a glass capillary viscometer. APPARATUS AND EXPERIMENTAL PROCEDURE The interfacial tension measurements described in this study were made by the pendent-drop method. The pendent-drop method is based on the formation of a drop of liquid on a tip, the drop being slightly smaller than that which will spontaneously detach itself from the tip. The profile of this drop is magnified by projection and can be recorded on a photosensitive emulsion. The interfacial tension is photosensitive emulsion. The interfacial tension is calculated from the dimensions of the drop profile, a knowledge of be densities of the liquid forming. the drop, and the bulk phase surrounding the drop. All interfacial tensions described in this paper were recorded at a temperature of 74 degrees F and at an interface age of 10 seconds. Most systems were studied as a function of temperature; but temperature was found to be a second-order effect, so we selected 74 degrees F in order that all correlations would be at constant temperature. We selected 10 seconds because a study of the time variable showed that most of the decay of interfacial tension with time in these systems had occurred by the end of 10 seconds. SPEJ P. 197

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^

scholarly journals Performance of asphaltene stability predicting models in field environment and development of new stability predicting model (ANJIS)

2021 ◽  
Author(s):  
Abdus Saboor ◽  
Nimra Yousaf ◽  
Javed Haneef ◽  
Syed Imran Ali ◽  
Shaine Mohammadali Lalji
Keyword(s):  
Crude Oil ◽  
Colloidal Stability ◽  
Stability Index ◽  
Crude Oils ◽  
Asphaltene Precipitation ◽  
Oil Composition ◽  
Stability Parameters ◽  
Predicting Model ◽  
Hydrocarbon Production ◽  
Asphaltene Deposition

AbstractAsphaltene Precipitation is a major issue in both upstream and downstream sectors of the Petroleum Industry. This problem could occur at different locations of the hydrocarbon production system i.e., in the reservoir, wellbore, flowlines network, separation and refining facilities, and during transportation process. Asphaltene precipitation begins due to certain factors which include variation in crude oil composition, changes in pressure and temperature, and electrokinetic effects. Asphaltene deposition may offer severe technical and economic challenges to operating Exploration and Production companies with respect to losses in hydrocarbon production, facilities damages, and costly preventive and treatment solutions. Therefore, asphaltene stability monitoring in crude oils is necessary for the prevention of aggravation of problem related to the asphaltene deposition. This study will discuss the performance of eleven different stability parameters or models already developed by researchers for the monitoring of asphaltene stability in crude oils. These stability parameters include Colloidal Instability Index, Stability Index, Colloidal Stability Index, Chamkalani’s stability classifier, Jamaluddin’s method, Modified Jamaluddin’s method, Stankiewicz plot, QQA plots and SCP plots. The advantage of implementing these stability models is that they utilize less input data as compared to other conventional modeling techniques. Moreover, these stability parameters also provide quick crude oils stability outcomes than expensive experimental methods like Heithaus parameter, Toluene equivalence, spot test, and oil compatibility model. This research study will also evaluate the accuracies of stability parameters by their implementation on different stability known crude oil samples present in the published literature. The drawbacks and limitations associated with these applied stability parameters will also be presented and discussed in detail. This research found that CSI performed best as compared to other SARA based stability predicting models. However, considering the limitation of CSI and other predictors, a new predictor, namely ANJIS (Abdus, Nimra, Javed, Imran & Shaine) Asphaltene stability predicting model is proposed. ANJIS when used on oil sample of different conditions show reasonable accuracy. The study helps Petroleum companies, both upstream and downstream sector, to determine the best possible SARA based parameter and its associated risk used for the screening of asphaltene stability in crude oils.

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^

SARA-Based Correlation To Describe the Effect of Polar/Nonpolar Interaction, Salinity, and Temperature for Interfacial Tension of Low-Asphaltene Crude Oils Characteristic of Unconventional Shale Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-13
Author(s):  
I. W. R. Saputra ◽  
D. S. Schechter
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Petroleum Engineering ◽  
Crude Oils ◽  
Oil Composition ◽  
Surface Activities ◽  
Low Salinity ◽  
Oil Water ◽  
Shale Reservoirs

Summary Oil/water interfacial tension (IFT) is an important parameter in petroleum engineering, especially for enhanced-oil-recovery (EOR) techniques. Surfactant and low-salinity EOR target IFT reduction to improve oil recovery. IFT values can be determined by empirical correlation, but widely used thermodynamic-based correlations do not account for the surface-activities characteristic of the polar/nonpolar interactions caused by naturally existing components in the crude oil. In addition, most crude oils included in these correlations come from conventional reservoirs, which are often dissimilar to the low-asphaltene crude oils produced from shale reservoirs. This study presents a novel oil-composition-based IFT correlation that can be applied to shale-crude-oil samples. The correlation is dependent on the saturates/aromatics/resins/asphaltenes (SARA) analysis of the oil samples. We show that the crude oil produced from most unconventional reservoirs contains little to no asphaltic material. In addition, a more thorough investigation of the effect of oil components, salinity, temperature, and their interactions on the oil/water IFT is provided and explained using the mutual polarity/solubility concept. Fifteen crude-oil samples from prominent US shale plays (i.e., Eagle Ford, Middle Bakken, and Wolfcamp) are included in this study. IFT was measured in systems with salinity from 0 to 24% and temperatures up to 195°F.

scholarly journals Asphaltene Stability of Some Iraqi Dead Crude oils

2019 ◽  
Vol 25 (3) ◽  
pp. 53-67
Author(s):  
Ali Anwar Ali ◽  
Mohammed S. Al-Jawad ◽  
Abdullah A. Ali
Keyword(s):  
Refractive Index ◽  
Crude Oil ◽  
Petroleum Ether ◽  
Oil Recovery ◽  
High Ratio ◽  
Crude Oils ◽  
Asphaltene Precipitation ◽  
Oil Composition ◽  
Point Pressure ◽  
The Dead

Asphaltene is one of the fractions of the crude oil which is soluble in aromatics such as benzene or toluene and insoluble in alkane such as n-heptane, n-pentane or petroleum ether (mixture of alkane compounds).  Asphaltene precipitation is one of the most common problems that sometimes occurs in both oil recovery and refinery processes as a result of changing in pressure, oil composition, or temperature. Therefore the stability of asphaltene in the crude oil must be studied to show the tendency of it for precipitating asphaltene to prevent it (Asphaltene precipitation and deposition problem) and eliminate the burden of high treatment costs. In the present study, saturate, aromatic, resin and asphaltene (SARA) analysis of the six dead crude oil samples from different Iraqi oil fields was conducted by using open column liquid chromatography after separating the asphaltene from them through filtration process. The asphaltene stability of dead crude oil samples was studied depending on changing the composition of them by adding the petroleum ether as an alkane and using colloidal instability index (CII) to determine the tendency of these crude oil samples to precipitate asphaltene depending on the SARA analysis results of these dead crude oils. All of dead crude oil samples showed the instability of asphaltene depending on this index and this means that all of them might precipitate asphaltene if the composition of these crude oil samples changed due to existing with the alkane in the live case in wells (Live oil is oil containing gas phase at reservoir conditions) such as injection of gas which has high ratio of alkane or the expanding the gas in the oil when the pressure decreases until reaches bubble point pressure. The refractive index of the dead crude oil samples was measured experimentally and calculated by two correlations which were Fan et al. correlation and Chamkalani correlation. The last one showed the best match between the experimental and calculated values of the refractive index of the dead crude oil samples.    

THE EFFECT OF CRUDE OIL COMPOSITION ON DISPERSANT PERFORMANCE

1985 ◽  
Vol 1985 (1) ◽  
pp. 441-444 ◽  
Author(s):  
Gerard P. Canevari
Keyword(s):  
Crude Oil ◽  
High Viscosity ◽  
Crude Oils ◽  
Chemical Compositions ◽  
Test Results ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Oil Emulsion ◽  
Dispersant Effectiveness ◽  
Water In Oil Emulsion

ABSTRACT Previously, anomalous results from various laboratory dispersant effectiveness tests were believed due to the historic difficulties of replicating field conditions in the laboratory. Some variables were reported to cause differences in dispersant performance, such as the oil viscosity—i.e., both dispersant A and dispersant B exhibited poorer performance as the oil viscosity increased. Other test results showed an opposite trend. For example, dispersant A performed more effectively than dispersant B for Murban crude oil but B was better than A for the more viscous La Rosa crude oil. It is now believed that these inconsistent results are actually due to the chemical compositions of the crude oils. Various factors influence dispersant performance and some initial research directed at determining the mechanism of water-in-oil emulsion (mousse) formation has identified naturally occurring surfactants in the various crude oils. This will provide insight as to how these indigenous agents interacted with the surfactant package in the test dispersant to affect overall performance. Variations in dispersant performance for different crude oils are thus likely to be related to the water-in-oil emulsion formation of the particular crude oil. The results of this work indicate that dispersant treatment should be evaluated during spill situations even if the crude oil physical properties, such as high viscosity, might suggest that dispersant treatment would not be effective.

scholarly journals Inorganic Geochemistry of Crude Oils of Northern Eurasia After ICP-MS Data as a Clear Evidence for Their Deep Origin

2021 ◽  
Author(s):  
Kirill Svyatoslavovich Ivanov ◽  
Yuriy Viktorovich Erokhin ◽  
Daniil Aleksandrovich Kudryavtsev
Keyword(s):  
Rare Earth ◽  
Crude Oil ◽  
Inductively Coupled Plasma ◽  
Limit Of Detection ◽  
Crude Oils ◽  
Northern Eurasia ◽  
Oil Composition ◽  
Inductively Coupled ◽  
Icp Ms ◽  
Microelement Composition

Emerging of mass-spectroscopy with inductively-coupled plasma (ICP-MS) made possible to study the microelement composition of crude oil and its derivatives (with the limit of detection at the ppt level). We have studied the crude oil composition of some West Siberian and Tatarstan oilfields with the ICP-MS method to detect 50 rare, rare-earth, and other microelements. The elemental composition is reasonably comparable to their concentrations in ultrabasites whereas the contents of most of the elements are low to the limit. On the diagrams of rare-earth elements, one can see the prevalence of light lanthanides and positive europium anomaly. The study shows that crude oils have a specific microelement composition that stands out from other geological systems.

Study of the Effect of Crude Oils on the Metallic Corrosion

2018 ◽  
Vol 5 (1) ◽  
pp. 43-54
Author(s):  
Suresh Aluvihara ◽  
Jagath K Premachandra
Keyword(s):  
Crude Oil ◽  
Sulfur Content ◽  
Salt Content ◽  
Ferrous Metal ◽  
Relative Weight ◽  
Oil Refining ◽  
Crude Oils ◽  
Hardness Tester ◽  
Corrosion Rates ◽  
Ferrous Metals

Corrosion is a severe matter regarding the most of metal using industries such as the crude oil refining. The formation of the oxides, sulfides or hydroxides on the surface of metal due to the chemical reaction between metals and surrounding is the corrosion that  highly depended on the corrosive properties of crude oil as well as the chemical composition of ferrous metals since it was expected to investigate the effect of Murban and Das blend crude oils on the rate of corrosion of seven different ferrous metals which are used in the crude oil refining industry and investigate the change in hardness of metals. The sulfur content, acidity and salt content of each crude oil were determined. A series of similar pieces of seven different types of ferrous metals were immersed in each crude oil separately and their rates of corrosion were determined by using their relative weight loss after 15, 30 and 45 days. The corroded metal surfaces were observed under the microscope. The hardness of each metal piece was tested before the immersion in crude oil and after the corrosion with the aid of Vicker’s hardness tester. The metallic concentrations of each crude oil sample were tested using atomic absorption spectroscopy (AAS). The Das blend crude oil contained higher sulfur content and acidity than Murban crude oil. Carbon steel metal pieces showed the highest corrosion rates whereas the stainless steel metal pieces showed the least corrosion rates in both crude oils since that found significant Fe and Cu concentrations from some of crude oil samples. The mild steel and the Monel showed relatively intermediate corrosion rates compared to the other types of ferrous metal pieces in both crude oils. There was a slight decrease in the initial hardness of all the ferrous metal pieces due to corrosion.

scholarly journals Evaluation of the Different Compatibility Indices to Model and Predict Oil Colloidal Stability and Its Relation to Crude Oil Desalting

Resources ◽  
2021 ◽  
Vol 10 (8) ◽  
pp. 75
Author(s):  
Ivelina K. Shishkova ◽  
Dicho S. Stratiev ◽  
Mariana P. Tavlieva ◽  
Rosen K. Dinkov ◽  
Dobromir Yordanov ◽  
...  
Keyword(s):  
Crude Oil ◽  
Colloidal Stability ◽  
Crude Oils ◽  
Oil Blend ◽  
Light Medium

Thirty crude oils, belonging to light, medium, heavy, and extra heavy, light sulfur, and high sulfur have been characterized and compatibility indices defined. Nine crude oil compatibility indices have been employed to evaluate the compatibility of crude blends from the thirty individual crude oils. Intercriteria analysis revealed the relations between the different compatibility indices, and the different petroleum properties. Tetra-plot was employed to model crude blend compatibility. The ratio of solubility blending number to insolubility number was found to best describe the desalting efficiency, and therefore could be considered as the compatible index that best models the crude oil blend compatibility. Density of crude oil and the n-heptane dilution test seem to be sufficient to model, and predict the compatibility of crude blends.

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