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^

scholarly journals Experimental Study on Reducing CO2–Oil Minimum Miscibility Pressure with Hydrocarbon Agents

Energies ◽  
2019 ◽  
Vol 12 (10) ◽  
pp. 1975 ◽  
Author(s):  
Junrong Liu ◽  
Lu Sun ◽  
Zunzhao Li ◽  
Xingru Wu
Keyword(s):  
Crude Oil ◽  
Petroleum Ether ◽  
Oil Recovery ◽  
Mass Concentration ◽  
Co2 Flooding ◽  
Oil Viscosity ◽  
Injection Wells ◽  
Boiling Range ◽  
Minimum Miscibility Pressure ◽  
Soluble Surfactants

CO2 flooding is an important method for improving oil recovery for reservoirs with low permeability. Even though CO2 could be miscible with oil in regions nearby injection wells, the miscibility could be lost in deep reservoirs because of low pressure and the dispersion effect. Reducing the CO2–oil miscibility pressure can enlarge the miscible zone, particularly when the reservoir pressure is less than the needed minimum miscible pressure (MMP). Furthermore, adding intermediate hydrocarbons in the CO2–oil system can also lower the interfacial tension (IFT). In this study, we used dead crude oil from the H Block in the X oilfield to study the IFT and the MMP changes with different hydrocarbon agents. The hydrocarbon agents, including alkanes, alcohols, oil-soluble surfactants, and petroleum ethers, were mixed with the crude oil samples from the H Block, and their performances on reducing CO2–oil IFT and CO2–oil MMP were determined. Experimental results show that the CO2–oil MMP could be reduced by 6.19 MPa or 12.17% with petroleum ether in the boiling range of 30–60 °C. The effects of mass concentration of hydrocarbon agents on CO2–oil IFT and crude oil viscosity indicate that the petroleum ether in the boiling range of 30–60 °C with a mass concentration of 0.5% would be the best hydrocarbon agent for implementing CO2 miscible flooding in the H Block.

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.

Analysis of Nitrogen Minimum Miscibility Pressure MMP and Its Impact on Instability of Asphaltene Aggregates - An Experimental Study

2021 ◽  
Author(s):  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Size Structure ◽  
Gas Injection ◽  
Injection Pressure ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Weight Percentage ◽  
Minimum Miscibility Pressure ◽  
The Impact

Abstract Minimum miscibility pressure (MMP) is a critical parameter when undergoing miscible gas injection operations for enhanced oil recovery (EOR). Miscibility has become a major term in designing the gas injection process. When the miscible gas contacts the reservoir oil, it causes changes in the basic oil properties, affecting reservoir oil composition and equilibrium conditions. Changes in conditions may also favor flocculation and deposition of organic solids, mainly asphaltene, which were previously in thermodynamic equilibrium. The main purpose of this study is to investigate how the most important parameters, such as oil temperature and oil viscosity, could affect the nitrogen (N2) MMP and the instability of asphaltene aggregation. Three sets of experiments were conducted: first, the determination of MMP was performed using a slim-tube packed with sand. The impact of crude oil viscosity using 32, 19, and 5.7 cp; and temperature using 32, 45, and 70 °C, were investigated. The results showed that the N2 MMP decreased when crude oil temperature increased. The temperature is inversely proportional to the N2 MMP due to the N2 remaining in a gaseous phase at the same conditions. In terms of viscosity, the MMP for N2 was found to decrease with the reduction in oil viscosity. Second, the effect of miscibility N2 injection pressure on asphaltene aggregation using 750 psi (below miscible pressure) and 1500 psi (at miscible pressure) was investigated using a specially designed filtration vessel. Various filter membrane pores sizes were placed inside the vessel to highlight the effect of asphaltene molecules on plugging the unconventional pore structure. The results demonstrated that increasing the pressure increased asphaltene weight percentage. The asphaltene weight percent was higher when using miscible injection pressure compared to immiscible injection pressure. Also, the asphaltene weight percentage increased when the pore size structure decreased. Finally, the visualization of asphaltene deposition over time was conducted, and the results showed that asphaltene particles started to precipitate after 2 hours. After 12 hours, the colloidal asphaltenes were fully precipitated.

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^

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.    

scholarly journals Determination of Minimum Miscibility Pressure of CO2–Oil System: A Molecular Dynamics Study

Molecules ◽  
2021 ◽  
Vol 26 (16) ◽  
pp. 4983
Author(s):  
Ding Li ◽  
Shuixiang Xie ◽  
Xiangliang Li ◽  
Yinghua Zhang ◽  
Heng Zhang ◽  
...  
Keyword(s):  
Molecular Dynamics ◽  
Crude Oil ◽  
Oil Recovery ◽  
Petroleum Industry ◽  
Co2 Flooding ◽  
Field Development ◽  
Whole Process ◽  
Minimum Miscibility Pressure ◽  
Pass Through ◽  
Relative Errors

CO2 enhanced oil recovery (CO2-EOR) has become significantly crucial to the petroleum industry, in particular, CO2 miscible flooding can greatly improve the efficiency of EOR. Minimum miscibility pressure (MMP) is a vital factor affecting CO2 flooding, which determines the yield and economic benefit of oil recovery. Therefore, it is important to predict this property for a successful field development plan. In this study, a novel model based on molecular dynamics to determine MMP was developed. The model characterized a miscible state by calculating the ratio of CO2 and crude oil atoms that pass through the initial interface. The whole process was not affected by other external objective factors. We compared our model with several famous empirical correlations, and obtained satisfactory results—the relative errors were 8.53% and 13.71% for the two equations derived from our model. Furthermore, we found the MMPs predicted by different reference materials (i.e., CO2/crude oil) were approximately linear (R2 = 0.955). We also confirmed the linear relationship between MMP and reservoir temperature (TR). The correlation coefficient was about 0.15 MPa/K in the present study.

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.

scholarly journals An experimental investigation of asphaltene stability in heavy crude oil during carbon dioxide injection

2019 ◽  
Vol 10 (3) ◽  
pp. 919-931 ◽  
Author(s):  
Sherif Fakher ◽  
Mohamed Ahdaya ◽  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Crude Oil ◽  
Pore Size ◽  
Oil Recovery ◽  
Asphaltene Precipitation ◽  
Carbon Dioxide Injection ◽  
Oil Viscosity ◽  
Membrane Pore ◽  
Pore Sizes ◽  
Filter Membrane

Abstract Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs.

Steam Distillation of Crude Oils

1983 ◽  
Vol 23 (02) ◽  
pp. 265-271 ◽  
Author(s):  
J.H. Duerksen ◽  
L. Hsueh
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Steam Distillation ◽  
Steam Injection ◽  
Hot Water ◽  
Saturated Steam ◽  
Crude Oils ◽  
Simulated Distillation ◽  
Distillation Temperature ◽  
Hydrocarbon Vapor

Abstract The objectives of this investigation were to generate crude oil steam distillation data for the prediction of phase behavior in steamflood simulation and to correlate the steam distillation yields for a variety of crude oils. Thirteen steam distillation tests were run on 10 crude oils ranging in gravity from 9.4 to 37 deg. API (1.004 to 0.840 g/cm3). In each test the crude was steam distilled sequentially at about 220, 300, 400, and 500 deg. F (104, 149, 204, and 260 deg. C). The cumulative steam distillation yields at 400 deg. F (204 deg. C) ranged from about 20 to 55 vol%. Experimental results showed that crude oil steam distillation yields at steamflood conditions are significant, even for heavy oils. The effects of differences in steam volume throughput and steam temperature were taken into account when comparing yields for different crudes or repeat runs on the same crude. Steam distillation yields show a high correlation with crude oil API gravity and wax content. Introduction Steam distillation is an important steamflood oil recovery mechanism, especially in reservoirs containing light oils. Injected steam heats the formation and eventually forms a steam zone, which grows with continued steam injection. A fraction of the crude oil in the steam zone vaporizes into the steam phase according to the vapor pressures of the hydrocarbon constituents contained in the crude oil. The hydrocarbon vapor is transported through the steam zone by the flowing steam. Both the steam and hydrocarbon vapor condense at the steam front to form a hot-water zone and a hydrocarbon distillate bank. The vaporization, transport, and condensation of the hydrocarbon fractions is a dynamic process that displaces the lighter hydrocarbon fractions and generates a distillate bank that miscibly drives reservoir oil to producing wells. The effect of steam distillation on oil recovery has been investigated in several laboratory studies, steamf lood field tests, and in simulation studies. In a critical review of steam flood mechanisms, Wu discussed the steam distillation mechanism in detail. Wu and Brown reported steam distillation yields for six crude oils ranging from 9 to 36 deg. API (1.007 to 0.845 g/cm3). When plotted against their steam distillation correlation parameter, Vw/Voi (the ratio of collected steam condensate, Vw, and initial oil volume, Voi), the yields were independent of the porous medium used, steam-injection rate, and initial oil volume. For the crude oils tested, they concluded that changing the saturated steam pressure and temperature had an insignificant effect on yield, but superheating the steam from 471 to 600 deg. F (244 to 316 deg. C) significantly increased the yield. Wu and Elder reported steam distillation yields for 16 crude oils ranging from 12 to 40 deg. API (0.986 to 0.825 g/cm3). Yields ranged from 12 to 56% of initial oil volume at a distillation temperature and pressure of 380 deg. F and 200 psig (193 deg. C and 1.379 MPa). Yields at Vw/Voi = 15 were correlated with three parameters:simulated distillation temperature of the oil at 20% yield,oil viscosity, andoil API gravity. The simulated distillation obtained by gas chromatography closely approximates the true boiling-point distillation as determined by ASTM distillation. The simulated distillation temperature at 20% yield gave the closest correlation with steam distillation yield. SPEJ P. 265^

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