Heavy Crude Oil Samples Research Articles

Laboratory measurements of solubility and swelling factor for CO2/Brine and CO2/heavy oil binary systems under low‐medium pressure and temperature

AbstractAn extensive experimental study was performed to investigate the effect of various parameters such as temperature, pressure, and crude oil API gravity on the fluid interactions in the binary systems of brine‐CO2 and two heavy oil‐CO2 systems. The solubility of CO2 in 20 000 ppm brine solution was measured at various experimental conditions. The solubility of CO2 and swelling factor, due to the CO2 dissolution, of two heavy crude oil samples (type‐I: °API = 20.44 and type‐II: °API = 15.49) were experimentally measured at various operating conditions.Results showed that the solubility of CO2 in heavy oil increased when the experimental pressure increased, and when the experimental temperature decreased. At a constant pressure of Pexp = 3.44 MPa, the solubility of the CO2 was measured to be 10.13, 5.72 g CO2/100 g oil in the type‐I crude oil when the temperature increased from T = 21 to 45 °C. Increasing the experimental pressure from Pexp = 1.38 MPa to 3.44 MPa at a constant temperature of T = 21 °C increased the solubility of the CO2 from 2.37 to 7.84 g CO2/100 g oil in the type‐II crude oil. The reduction in the oil API gravity had an adverse effect on the CO2 solubility. At a temperature of T = 21 °C and a pressure of Pexp = 3.44 MPa, the CO2 solubility decreased from ∼10.13 in the type‐I oil to 7.84 g CO2/100 g oil in the type‐II oil. The measured values of the swelling factor showed that the type‐I and type‐II crude oils could exhibit a maximum swelling factor of 1.079 and 1.052 at a temperature of T = 21 °C and a pressure of Pexp = 3.44 MPa.

Mixing of Crude Oil with Organic ZnO Nano-Particles from Rice Bran to Improve Physical Properties of Crude Oil: A Novel Agent for Enhanced Oil Recovery

In this study, ZnO nanoparticles were modified with rice bran. Synthesis and production of ZnO nano-particles is highly important due to the use of rice bran. In addition, XRD and SEM analyses were used to ensure the production quality of the nano-particles. The images clearly showed surface uniformity of the synthesized organic ZnO nano-particles. Afterward, the modified nano-particles were injected into crude oil in different weight percentages according to their properties (heavy and light crude oil). The injection was done at a temperature range of 30–150 °C with operating pressures varying from 10 bar to 300 bar. The adhesion force created between heavy or light crude oil molecules and organic ZnO nano-particles was modified with rice bran. Furthermore, an increase in the operating temperature increased the thermal conductivity of oil samples from 0.21 to 2.54 W/m °C for the light crude oil sample and 1.56–6.3 W/m °C for the heavy crude oil sample. The results showed that the percentage of the asphaltene precipitation decreased with the increased API of the crude oil. In addition, the percentage of asphaltene precipitation for nano-light and heavy crude oil was considerably better than the simple light and heavy crude oil samples, respectively. The nano-particles improved the crude oil recovery from reservoirs. The results indicate that the probability of asphaltene precipitation in the case of light crude oil nano-particles is less than the simple light crude oil by 28.3%. This is 8.1% for the heavy crude oil compared to the simple heavy crude oil.

Measurements and predictions of Middle Eastern heavy crude oil viscosity using compositional data

Determining the viscosity of heavy crude oil is important in the field of petroleum science, and reservoir simulators are routinely used to achieve this goal. In this study, a new empirical model for predicting heavy-oil viscosity is presented. The model was developed using the compositional data of 28 heavy crude oil samples from the Middle East. Viscosity measurements from 196 data points in the 20–80 °C temperature range were used during model development, and another 47 viscosity measurements were used to validate the model. The compositional and viscosity measurements were also used to evaluate the accuracy of previously published methods for predicting heavy-oil viscosities. These methods include corresponding-states models, residual viscosity models, and equations-of-state-based models. The study reveals that none of the previously published methods adequately predict the viscosities of heavy crude oils. On the other hand, it shows that the new empirical model is able to predict the viscosities of heavy oils with an average relative error of 3.8%. The proposed model is much simpler and easier to use than existing methods.

Modeling viscosity of moderate and light dead oils in the presence of complex aromatic structure

Crude oil viscosity measurements are very crucial in the field of petroleum industries. Difficulties associated with obtaining accurate measured viscosity values for reservoir oils have turned the light to estimate viscosity through empirical correlations to alleviate these laboratory difficulties. This work is a supplementary study for a previous research work, done on Egyptian heavy crude oil samples, to cover all types of reservoir oils. The proposed work started with evaluating the previously published viscosity correlations that considered as a useful method to provide preliminary values for viscous oil reservoirs characterization. The obtained viscosity values showed poor performance of applying these correlations, as these correlations depend only on oil specific gravity and operating temperature. Therefore, there is a need for correlating a new effective viscosity model using asphaltene content as one of the main representative parameters. Asphaltene is considered as a complex aromatic structure which causes problems in reservoir oils. In this work, laboratory measurements have been made on five-hundred database points of Egyptian moderate and light dead oil samples obtained from different locations to build accurate viscosity correlation model. The best fit accurate empirical correlation has been found using multiple least-square nonlinear regression analysis for ranges of viscosity measurements from 23.06 to 43.18 OAPI. Testing of the new proposed viscosity model, with another set of laboratory measured viscosity data, shows high performance and accuracy in predicting Egyptian moderate and light dead crude oils viscosity as compared with literature viscosity correlations.

Experimental study of polymer injection enhanced oil recovery in homogeneous and heterogeneous porous media using glass-type micromodels

In water flooding process, volumetric sweep efficiency and oil recovery can be enhanced using polymer to increase the viscosity of water. As a result, polymer flooding has higher recovery as compared to water flooding due to front stability and reduction of fingering problem. In this research work, a set of polymer flooding runs were carried out using glass-type micromodels. The micromodels were fabricated to have homogeneous and heterogeneous flow patterns. They were positioned horizontally and saturated with a heavy crude oil sample taken from an Iranian oil field before starting the injection. Three commercial polymers were used in this study. Whole process was photographed continuously with a high-resolution camera to monitor the displacement of polymer solution in the micromodels. As a part of this study, the effect of different parameters including polymer solution concentration, injection flow rate and heterogeneity on performance of polymer flooding was investigated. On top of the regular homogeneous and heterogeneous flow patterns used in this study, a heterogeneous flow pattern mimicking sandstone reservoirs was created based on the image of a thin section of a sandstone (outcrop) and polymer front movement was observed during injection.

Experimental investigation of comparing electromagnetic and conventional heating effects on the unconventional oil (heavy oil) properties: Based on heating time and upgrading

This study examined the effects of microwave on Sarvak heavy crude oil sample from a reservoir in southwest Iran in a Fischer assay and heated by microwave for 2 min time steps until 14 min total heating time had elapsed. Unlike conventional heating, which caused light carbonic components to escape and raised C20+ components in oil samples, the value of light carbonic components increased under microwave heating. These materials cannot escape the oil sample in microwave heating because the cracked components approach a superheated state, and in this study a large portion of them remained. The sulfur content of heavy oil in microwave heating tends to decrease over time, approaching 16% at 14 min; in contrast, in conventional heating it remains constant. Sulfur is removed from the oil sample as H2S and SO2, predominantly in a gas state, but also as condensate, in increasing amounts over time. Sulfur removal from the heavy crude oil sample is highly important in the upgrading process because of having its high coefficient of microwave absorption. Saturation, Aromatic, Resin and Asphaltene (SARA) components analysis shows changes in the resin and asphaltene components. The amount of asphaltene components begins to decline starting early in the heating process, and approaches its lowest amount at 8 min (26% reduction). Reduction of resin components in microwave heating begins at 10 min and reaches 61% at 14 min. According to Fourier transform infrared (FTIR) spectra results, microwave irradiation caused cracking of large-chain molecules and drove light components from heavy crude sample. These two phenomena are a function of radiation time. The rate of cracking of heavy components was continuously greater than the rate of light components leaving the sample at early time intervals; ultimately, this resulted in an upgraded heavy oil.

High-resolution NMR study of light and heavy crude oils: “structure-property” analysis

Measurements of three light and one heavy crude oil samples were carried out by high-resolution nuclear magnetic resonance (NMR) spectroscopy methods. Quantitative fractions of aromatic molecules and functional groups constituting oil hydrocarbons were determined, and comparative analysis of the oil samples of different viscosity and origin was done.

Study on weathering characteristic of aromatic hydrocarbons specific to unconditional oil based on concentration-resolved-fluorescence spectroscopy

With the rapid decline of conventional crude oil’s production and transportation, heavy crude oil, heavy oil, oil sands, oil shale and other unconventional oil have gradually become the main body of the marine oil spills. The used oil spill fingerprinting methods mainly for conventional oil are facing new challenges. According to the time-resolved fluorescence spectroscopy, concentration value is introduced as a new data dimension to the fluorescence spectra and the concentration-resolved-fluorescence spectroscopy (CRFS) is developed to express more PAHs information. Laboratory simulation experiments of weathering and distillation were carried out and the results demonstrate this method has strong anti-weathering and anti-interference ability. Oil source classification of close-related heavy crude oil samples under light weathering and seawater weathering lasting 120 d are studied. 96% of the correct rate for the closely related oil source samples is achieved by combining Gabor wavelet with supported vector machine (SVM). The obtained results suggest that the newly-developed method may become specifically applicable in spilled oils identification and also can be applied to other multi-fluorophoric systems such as in petroleum exploration, dissolved organic matter in environment monitoring and petroleum exploration.

Gas chromatographic sulphur speciation in heavy crude oil using a modified standard D5623 method and microfluidic Deans switching

A modification to American Society for Testing and Materials (ASTM) method D5623 is proposed to enable successful and repeatable analysis of heavy crude oil samples. A two-dimensional gas chromatography configuration was implemented, with separation of sulphur compounds occurring on two columns. A Deans switch is used to enable heart-cutting of volatile sulphur compounds onto a DB-Sulfur stationary phase, and separation occurs concurrently with the backflushing of the primary column. The use of a sulphur-selective detector increases selectivity, and 22 volatile sulphur species are quantified in less than 15min, which is almost half the time of the original ASTM method. Samples ranging from light distillation cuts to whole crudes (boiling from 100°C to >750°C) were analyzed with minimal sample preparation. The calculated limit of detection was 0.7mg/kg, repeatability was 3% relative standard deviation (RSD), and a linear range of 1–250mg/kg was obtained, with an R2 value of 0.994 or better, depending on the compound.

The experimental investigation of effect of microwave and ultrasonic waves on the key characteristics of heavy crude oil

This study examined the effects of microwave (MW) and ultrasonic (US) waves on an heavy crude oil sample from a reservoir in southwest Iran. The waves irradiated the sample from two to 10min at two-minute steps. MW caused the temperature of the crude-oil sample to rise by selective heating of polar components and creation of hot zones; under US, heating was accompanied by a cavitation effect. MW at 2 and 4min reduced the sample’s viscosity by inducing hot zones. At 2min, the viscosity declined 16% due to cracking of heavy components such as asphaltenes, which have a higher capacity to absorb MW. As the radiation time increased after 4min, the viscosity increased because light components escaped from the sample. However, US reduced the viscosity of the heavy crude oil sample at all time durations. The greatest reduction of viscosity was around 19%, at 4min. The viscosity increased with irradiation time and then remained constant. Ultrasonic waves altered the viscosity by creating bubbles, which disintegrated the resin intermolecular bonds and cracked the large molecular particles of the asphaltene. The reduction in sulfur content under US was much greater than under MW. At all time durations, sulfur content fell as radiation time increased. Due to its high potential to absorb MW, creates active sulfur that can be emitted from the crude oil as sulfide and hydrogen sulfide, with the sulfur level falling to 0.39%. Furthermore, US waves also reduced sulfur content to around 0.46% as the asphaltene flocks disintegrated. Reduction of sulfur content from asphaltene agglomerates under MW and US was observed using scanning electron microscopy (SEM) and energy dispersive spectroscopy (EDS). In addition to reducing the effect of sulfur by affecting its nitrogen and oxygen elements, irradiation also reduced the polarity of the asphaltene particles and prevented reaggregation of cracked particles. Results of SARA (saturation, aromatic, resin and asphaltene) analysis showed that asphaltene particles have a higher capacity to absorb MW than resin components, as after the amount of asphaltene components declined in the early stages of irradiation, resin components began to change, falling to 34% at 10min. The decrease in asphaltene content in samples under US was more evident, reaching 34% at 8min. According to Fourier transform infrared (FTIR) spectra results, MW irradiation caused cracking of large-chain molecules and drove light components from heavy crude sample. These two phenomena are a function of radiation time. The rate of cracking of heavy components was continuously greater than the rate of light components leaving the sample at early time intervals; ultimately, this resulted in an upgraded heavy oil. In some cases, despite cracking of large-chain molecules and creation of light components, the output values of light components were higher. Under US, the cracking of large-chain molecules occurred, but due to the departure of heavy components from the crude oil, peak intensities increased and the resulting crude oil had purer components.

The experimental study of effect of microwave heating time on the heavy oil properties: Prospects for heavy oil upgrading

A heavy crude oil sample from an oil field in southwest Iran was placed in a Fischer assay and heated by microwave for two-minute time steps until 14min total heating time had elapsed. Unlike conventional heating technique (CHT), which caused light carbonic components to escape and raised C20+ components in oil samples, the value of light carbonic components increased under microwave heating technique (MHT) up to 6min. These materials cannot escape the oil sample in MHT because the cracked components approach a superheated state, and in this study a large portion of them remained at 6min. Moreover, in contrast to the CHT results, the C1–C20 components increased to 13.5wt% in the analysis of cracked gases during MHT. In MHT, light components increased with heating time, and C7+ components fell. This is indicative of light components escaping after 6min. Some components escaped as condensate. In CHT, the escape of only small amounts of condensates was observed at 12 and 14min, while under MHT, this phenomenon started at 8min and contained larger amounts. This phenomenon is due to secondary cracking in oil, which is created by an abrupt increase in the temperature of some components that have more capacity to absorb microwaves. The sulfur content of heavy oil in MHT tended to decrease over time, approaching 34wt% at 14min; in contrast, in CHT it remained constant. Sulfur was removed from the oil sample as H2S and SO2, predominantly in a gas state, but also as condensate, in increasing amounts over time. Sulfur removal from the heavy crude oil sample is highly important in the upgrading process because of its high coefficient of microwave absorption. H2S is produced from the start of MHT, but SO2 is observed only after 6min, and then only in the produced gas. Saturation, Aromatic, Resin and Asphaltene (SARA) components analysis showed changes in the resin and asphaltene components. The amount of asphaltene components began to decline starting early in the heating process, and approached its lowest amount at 4min (3.21wt%). Reduction of resin components in MHT began at 8min and reached 55% at 14min. Asphaltenes have a high capability to absorb microwaves due to having SNO (Sulfur, Nitrogen and Oxygen) components that create hot zones in heavy oil; these hot zones enhance cracking and upgrading. Scanning electron microscopy images of asphaltene particles showed that microwaves caused some changes in the structure of these particles. Energy-dispersive spectroscopy analysis of these particles showed that SNO components under MHT declined over heating time. The results also suggest that after sulfur, nitrogen and oxygen have the highest potential to absorb microwaves.

Wettability alteration of sandstones by silica nanoparticle dispersions in light and heavy crude oil

Unlike conventional oil production methods, enhanced oil recovery (EOR) processes can recover most oil products from the reservoir. One method, known as wettability alteration, changes the hydrophilicity of the reservoir rock via decreased surface interactions with crude oils. The mitigation of these attractive forces enhances petroleum extraction and increases the accessibility of previously inaccessible rock deposits. In this work, silica nanoparticles (NPs) have been used to alter the wettability of two sandstone surfaces, Berea and Boise. Changes in wettability were assessed by measuring the contact angle and interfacial tension of different systems. The silica NPs were suspended in brine and a combined solution of brine and the Tween®20 nonionic surfactant at concentrations of 0, 0.001, and 0.01 wt% NP with both light and heavy crude oil. The stability of the different nanofluids was characterized by the size, zeta potential, and sedimentation of the particles in suspension. Unlike the NPs, the surfactant had a greater effect on the interfacial tension by influencing the liquid-liquid interactions. The introduction of the surfactant decreased the interfacial tension by 57 and 43% for light and heavy crude oil samples, respectively. Imaging and measurements of the contact angle were used to assess the surface-liquid interactions and to characterize the wettability of the different systems. The images reflect that the contact angle increased with the addition of NPs for both sandstone and oil types. The contact angle in the light crude oil sample was most affected by the addition of 0.001 wt% NP, which altered both sandstones’ wettability. Increases in contact angle approached 101.6% between 0 and 0.001 wt% NPs with light oil on the Berea sandstone. The contact angle however remained relatively unaffected by addition of higher NP concentrations, thus indicating that low NP concentrations can effectively be used for enhancing crude oil recovery. While the contact angle of the light crude oil plateaued, the heavy crude oil continued to increase with an increase in NP concentration; therefore indicating that a maximum contact angle in heavy crude oil was not yet achieved. The introduction of NPs in light and heavy crude oil samples altered both the Berea and Boise sandstone systems’ wettability, which in turn indicated the efficacy of the silica NPs and surfactants in generating a more water-wet reservoir. Consequently, silica NPs and surfactants are most promising for EOR across the range of oil types.

Aggregation behavior of asphaltene of different crude oils as viewed from solution surface tension measurement

Deposition of asphaltene critically affects crude oil production and refining. Deposition extent depends on condition and crucially on the nature and chemical structure of asphaltene. Diversity of crude oil reservoirs makes the measuring technique, method, and deposition modeling an active field of research. In this work, solution of asphaltene sample (in toluene) of three oil reservoirs Gachsaran, Bangestan, and Kuh-e-Mond were studied to understand and characterize asphaltenes behavior at surface and aggregation in bulk by surface tension measurement. The surface tension was measured under liquid-vapor equilibrium by capillary rise method as a function of asphaltene concentration (13.3–2660ppm) in the temperature range of 298–333K. At very low concentrations (<200ppm), the surface tension of three samples is rather high and close to the surface tension of neat solvent. As the concentration increases (up to 266ppm), surface tension decreases with a dip minimum characteristics of each reservoir. Therefore, at the low characteristics concentration (266ppm), asphaltene highly adsorbed to the solution surface. At the high characteristic concentration (1700ppm) aggregation may occur solely in bulk, at surface, or both depending on the asphaltene nature and temperature. As a result, an aggregation phenomenon at specific solution concentration represents the structural feature of each asphaltene sample. Overall, while the dependence on temperature is enhanced at higher concentration, asphaltene of the three reservoirs can be characterized by the concentration and temperature dependence of their solutions surface tension. Conclusively, the surface tension of asphaltene of Gachsaran (light crude oil) show strong dependence on concentration at low and high characteristic concentrations, while no such dependence is seen for Bangestan and Kuh-e-Mond (both of heavy crude oil) samples at high concentrations. These results are highly correlated with the reported asphaltene deposition features of each oil field.

Extraction induced by emulsion breaking for the determination of As, Co, Cr, Mn, Mo and Pb in heavy and extra-heavy crude oil samples by ICP-MS

A novel method based on extraction induced by emulsion breaking was performed for determination of metals in crude oil samples by ICP-MS.

Effect ­­­­­of ultrasonic irradiation treatment on rheological behaviour of extra heavy crude oil: A solution method for transportation improvement

AbstractThe highly viscous property of heavy oil often causes problems in its transportation in pipelines. Mixing heavy oil with light oil as well as ultrasound treatment are viable solutions to this problem. In this study, extra heavy crude oil samples were first diluted with 0, 0.05, 0.1, and 0.15 mL/mL (0, 5, 10, and 15 vol%) of a light crude oil; then the mixture was irradiated by ultrasonic waves for 0, 5, 10, 15, and 20 min; finally the viscous shear functions of all mixtures was measured at different values of shear rate at different temperature levels. The results revealed that the minimum viscosity of the diluted extra heavy crude oil samples was obtained at 10 min of ultrasonic irradiation. Moreover, the viscosity reduction rate in relation to temperature decreases as temperature increases. In other words, the maximum viscosity reduction rate occurred at 0.05 mL/mL (5 vol%) of light crude oil. Using the experimental data, the parameters of common rheological models were obtained and a new modified Power Law model was presented to calculate the effect of shear rate and temperature simultaneously.

Chemical–physical analysis of rheologically different samples of a heavy crude oil

Heavy crude oil samples extracted from the same well showed some rheological differences mainly in terms of viscosity and response to the addition of a small amount of dodecyl benzen sulfonate. Also slight differences in the activation energy and in the viscosity dependence on a solvent concentration were observed. The crude oil samples, also separated in maltenic and asphaltenic fractions, were fully characterized by elemental and proximate analysis, solvent extraction, thermogravimetry, mass spectrometric and spectroscopic analyses. No significant differences were found showing that the samples have the same composition and molecular structure and demonstrating that the different rheological behavior has to be related only to a different microstructural organization that is not sensed by the chemical–physical tests. This result helps to complete the picture of the complex correlation between rheological and chemical–physical properties of heavy crude oils. While it is accepted that chemical-physically different samples may, or may not, have a different rheology, we show for the first time that unperturbed samples with the same chemical–physical properties may exhibit differences in the rheological behavior.

Effect of Asphaltenes and Resins on Asphaltene Aggregation Inhibition, Rheological Behaviour and Waterflood Oil-Recovery

This study presents an investigation about the influence of resins and asphaltenes, extracted from two Mexican crude oils (light and heavy oil samples), on the asphaltene aggregation inhibition, rheological behavior, and waterflood oil-recovery. Resins and asphaltenes were characterized by means of elemental analysis, metals analysis by atomic absorption, 1H and 13C nuclear magnetic resonance (NMR) spectroscopy, and electrospray ionization mass spectrometry (ESI-MS) in order to evaluate the effect of their structural parameters on the phenomena studied. Efficiency of the resins fraction as natural inhibitors of asphaltene aggregation was evaluated trough ultraviolet–visible (UV–vis) spectroscopy. Results showed better efficiencies of resins on asphaltene aggregation inhibition at resin/asphaltene (R/A) ratios close to unity and at high temperature. In addition, efficiencies were influenced by structural characteristics of the asphaltene–resin system. Rheological behavior of the heavy crude oil sample was significantly influenced by the presence of asphaltenes and resins. Finally, asphaltenes and resins played an important role on wettability and waterflood oil-recovery.

Ecofreindly, candle precursor (Paraffin wax) production by Iranian indigenous bacterium to reduce the indoor health risks

The potential indoor air impacts of burning candles have drawn increased attention in recent years. Burning paraffin waxes itself, regardless to wick and the essence, produce some allergens and even carcinogenic compounds. Further biorefining of petroleum paraffin wax with proper bacteria is one of the proposed resolutions to decrease the health threat. Therefore in this study Iranian heavy crude oil sample were screened for the best isolate to reach the target. Manual culture and plate count method and screening were done in MSM medium supplemented with paraffin wax as the sole source of carbon and energy in 40°C and 150rpm. The growth curve of the best isolate was depicted through spectrophotometry during 24 hours. Then the isolate was characterized by biochemical test and molecular identification using 16srRNA. The spore forming, biosurfactant producing bacterium was identified as Bacillus cereus. Gas chromatogaraphs revealed the efficient degradation of long chain paraffin wax with the selected Bacillus cereus into 15 to 25 carbon length n- alkanes. The high physicochemical endurance of this bacterium including salinity tolerance from 0.5to 15 percent, pH from 4 to 10 and temperature growth range from 40 to 65°C, makes it a decent choice for industrial and environmental approaches.

Microwave Heating as an Enhanced Oil Recovery Method—Potentials and Effective Parameters

Different thermal techniques are used worldwide to increase recovery from heavy and ultra-heavy oil reservoirs. The conventional techniques of thermal enhanced oil recovery methods, because of excessive heat loss are not effective for recovery heavy oil reservoirs or deep wells. One way to introduce heat to the reservoir in a controlled manner is microwave heating. Different experiences showed that the successful production by microwave heating strongly depends on the initial conditions of the reservoir, such as initial water saturation and water salinity. The criteria for these parameters to improve the performance of the method are not well known yet. In this project, different experiments were conducted to study the effects of the main parameters on the performance of enhanced oil recovery by microwave heating. A Teflon core holder packed with glass beads was designed to study the recovery of a heavy crude oil sample from an Iranian reservoir under microwave heating. The core was saturated by crude oil and water and the influences of operational parameters, such as heating time, salinity, and initial water saturation on wave absorption were tested. The authors’ experiment showed that the main mechanisms for enhancing the oil recovery were gravity drainage and movement due to viscosity reduction.

Experimental investigation of CO2-foam stability improvement by alkaline in the presence of crude oil

Dissolution of CO2 in heavy crude oil results in a significant reduction in the oil viscosity. However, CO2 injection in viscous oil reservoirs lacks acceptable sweep efficiency due to the high mobility of CO2. Co-injection of CO2 and an appropriate surfactant can generate CO2-foam in situ providings a means of controlling CO2 mobility and hence, improving sweep efficiency and oil recovery. Foam injection has been studied in the past but in the majority of these studies, foam has been investigated in the absence of crude oil. It is known that the stability of foam is adversely affected by crude oil and this problem has been a major obstacle for the application of foam injection for enhanced oil recovery (EOR).In this paper we present the results of a comprehensive series of visual experiments on foam stability in the presence of different heavy crude oil samples. Through these experiments, we have evaluated and compared the performance of a number of surfactants for foam generation. We have also tested the impact of three different alkalis (NaOH, Na2CO3, and Borate) on foam stability. The effect of gas type (CO2 versus N2) has also been investigated experimentally.The results show that while addition of NaOH drastically decreases the stability of CO2-foam, Na2CO3 and, in particular, Borate can significantly increase the stability of CO2-foam. For these alkalis, there is an optimum concentration which corresponds to maximum foam stability. The results also reveal that higher oil viscosity increases the stability of CO2-foam. Anionic surfactants with smaller carbon number produce better foam stability compared to non-anionic surfactants. As expected, foam stability increased with increasing surfactant concentration but there was an optimum surfactant concentration corresponding to maximum foam stability beyond which foam stability decreased. The results also revealed that N2-foam was more stable compared to CO2-foam.