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.

New Colloidal Stability Index for Crude Oils Based on Polarity of Crude Oil Components

2010 ◽  
Vol 24 (12) ◽  
pp. 6483-6488 ◽  
Author(s):  
Victor V. Likhatsky ◽  
Rustem Z. Syunyaev
Keyword(s):  
Crude Oil ◽  
Colloidal Stability ◽  
Stability Index ◽  
Crude Oils ◽  
Oil Components

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.    

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.

Asphaltene Deposition Induced by Carbon Oxide and its Influence on Displacement Efficiency

2012 ◽  
Vol 594-597 ◽  
pp. 2451-2454
Author(s):  
Feng Lan Zhao ◽  
Ji Rui Hou ◽  
Shi Jun Huang
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Carbon Oxide ◽  
Viscosity Reduction ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Asphaltene Deposition ◽  
Total Oil

CO2is inclined to dissolve in crude oil in the reservoir condition and accordingly bring the changes in the crude oil composition, which will induce asphaltene deposition and following formation damage. In this paper, core flooding device is applied to study the effect of asphaltene deposition on flooding efficiency. From the flooding results, dissolution of CO2into oil leads to recovery increase because of crude oil viscosity reduction. But precipitated asphaltene particles may plug the pores and throats, which will make the flooding effects worse. Under the same experimental condition and with equivalent crude oil viscosity, the recovery of oil with higher proportion of precipitated asphaltene was relatively lower during the CO2flooding, so the asphltene precipitation would affect CO2displacement efficiSubscript textency and total oil recovery to some extent. Combination of static diffusion and dynamic oil flooding would provide basic parameters for further study of the CO2flooding mechanism and theoretical evidence for design of CO2flooding programs and forecasting of asphaltene deposition.

THE COLLOIDAL STABILITY OF CRUDE OILS AND CRUDE OIL RESIDUES

1999 ◽  
Vol 17 (3-4) ◽  
pp. 349-368 ◽  
Author(s):  
Horst Laux ◽  
Iradj Rahimian ◽  
Peter Schorling
Keyword(s):  
Crude Oil ◽  
Colloidal Stability ◽  
Crude Oils

Review of the Molecular Structure and Aggregation of Asphaltenes and Petroleomics

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 48-57 ◽  
Author(s):  
Oliver C. Mullins
Keyword(s):  
Pressure Drop ◽  
Crude Oil ◽  
Common Knowledge ◽  
Oil Refining ◽  
Crude Oils ◽  
Strong Temperature Dependence ◽  
Specific Chemical ◽  
Asphaltene Content ◽  
Asphaltene Deposition ◽  
Asphaltic Materials

Summary Tremendous strides have been made recently in asphaltene science. Many advanced analytical techniques have been applied recently to asphaltenes, elucidating many asphaltene properties. The inability of certain techniques to provide correct asphaltene parameters has also been clarified. Longstanding controversies have been resolved. For example, molecular structural issues of asphaltenes have been resolved; in particular, asphaltene molecular weight is now known. The primary aggregation threshold has recently been established by a variety of techniques. Characterization of asphaltene interfacial activity has advanced considerably. The hierarchy of asphaltene aggregation has emerged into a fairly comprehensive picture, essentially in accord with the Yen model with the additional inclusion of certain constraints. Crude oil and asphaltene science is now poised to develop proper structure-function relations that are the defining objective of the new field: petroleomics. The purpose of this paper is to review these developments in order to present a more clear and accessible picture of asphaltenes, especially considering that the asphaltene literature is a bit opaque. Introduction The asphaltenes are a very important class of compounds in crude oils (Chilingarian and Yen 1978; Bunger and Li 1981; Sheu and Mullins 1995; Mullins and Sheu 1998; Mullins et al. 2007c). The asphaltenes represent a complex mixture of compounds and are defined by their solubility characteristics, not by a specific chemical classification. A common (laboratory) definition of asphaltenes is that they are toluene soluble, n-heptane insoluble. Other light alkanes are sometimes used to isolate asphaltenes. This solubility classification is very useful for crude oils because it captures the most aromatic portion of crude oil. As we will see, this solubility defintion also captures those molecular components of asphaltene that aggregate. Other carbonaceous materials such as coal do possess an asphaltene fraction, but that often will not correspond to the most aromatic fraction. Petroleum asphaltenes, the subject of this paper, can undergo phase transitions that are an impediment in the production of crude oil. Fig. 1 shows a picture of an asphaltene deposit in a pipeline; obviously, asphaltene deposition is detrimental to the production of oil. Immediately it becomes evident that different operational definitions apply for the term asphaltene in the field vs. the lab. Indeed, the field deposit is very enriched in n-heptane-insoluble, toluene-soluble materials, but this field asphaltene deposit is not identically the standard laboratory solubility class. It is common knowledge that a pressure drop on certain live crude oils (containing dissolved gas) can cause asphaltene flocculation, the first step in creating deposits that are seen in Fig. 1. Highly compressible, very undersaturated crude oils are most susceptible to asphaltene deposition problems with a pressure drop (de Boer et al. 1995). In depressurization flocculation, the character of the asphaltene flocs is dependent on the extent of pressure drop, suggesting some variations in the corresponding chemical composition (Hammami et al. 2000; Joshi et al. 2001). Comingling different oils can result in asphaltene precipitation that can resemble solvent precipitation. Asphaltenes are hydrogen-deficient compared to alkanes; thus, either hydrogen must be added or coke removed in crude oil refining to generate transportation fuels. Thus, asphaltene content lowers the economic value of crude oil. Increasing asphaltene content is associated with dramatically increasing viscosity, especially at room temperature; again, this is of operational concern. The strong temperature dependence of viscosity of asphaltic materials is one of their important properties that make them useful for paving and coating; application of asphaltic materials is facile at moderately high temperatures, while desired rheological properties are obtained at ambient temperatures.

scholarly journals A Study of Asphaltene Precipitation Problem in some wells in Kurdistan Region

2020 ◽  
Vol 4 (6) ◽  
pp. 27-36
Author(s):  
akram Humoodi ◽  
Baroz Aziz ◽  
Dana Khidhir
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil And Gas ◽  
Surface Condition ◽  
Oil And Gas Industry ◽  
Kurdistan Region ◽  
Asphaltene Precipitation ◽  
Oil Composition ◽  
Reservoir Conditions ◽  
Point Pressure

Throughout the production and reservoir lifecycle, the asphaltene precipitation is an ever existing problem through changing the porosity, permeability and wettability leading to decline in production. The conditions that govern Asphaltene precipitation varies from well to well and from reservoir conditions of high pressure and temperature to surface conditions and need to be studied case by case. The modeling and predicting the phase behavior and precipitation of Asphaltene is paramount for wells in Kurdistan region as it is developing its oil and gas industry. Crude oil samples from three wells in Kurdistan Region-Iraq were selected for this study. Experimental data such as crude oil composition using Gas Chromatography, PVT analysis and reservoir pressure and temperature were used as input data into Computer Modeling Group CMG simulator and a model of Asphaltene phase behavior was suggested. The model suggests that the maximum precipitation occurs near the bubble point pressure at reservoir conditions. This is validated and compared with results in literature indicating similar behavior of crude oil. To predict the Asphaltene precipitation at surface condition a modified Colloidal Instability Index CII were used and the results were validated by De Bore plot

scholarly journals A Study of Asphaltene Precipitation Problem in some wells in Kurdistan Region

2020 ◽  
Vol 4 (6) ◽  
pp. 27-36
Author(s):  
akram Humoodi Abdulwahab ◽  
Baroz Aziz ◽  
Dana Khidhir
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil And Gas ◽  
Surface Condition ◽  
Oil And Gas Industry ◽  
Kurdistan Region ◽  
Asphaltene Precipitation ◽  
Oil Composition ◽  
Reservoir Conditions ◽  
Point Pressure

Throughout the production and reservoir lifecycle, the asphaltene precipitation is an ever existing problem through changing the porosity, permeability and wettability leading to decline in production. The conditions that govern Asphaltene precipitation varies from well to well and from reservoir conditions of high pressure and temperature to surface conditions and need to be studied case by case. The modeling and predicting the phase behavior and precipitation of Asphaltene is paramount for wells in Kurdistan region as it is developing its oil and gas industry. Crude oil samples from three wells in Kurdistan Region-Iraq were selected for this study. Experimental data such as crude oil composition using Gas Chromatography, PVT analysis and reservoir pressure and temperature were used as input data into Computer Modeling Group CMG simulator and a model of Asphaltene phase behavior was suggested. The model suggests that the maximum precipitation occurs near the bubble point pressure at reservoir conditions. This is validated and compared with results in literature indicating similar behavior of crude oil. To predict the Asphaltene precipitation at surface condition a modified Colloidal Instability Index CII were used and the results were validated by De Bore plot

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).

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^

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