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.

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.

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.

Minimum Miscibility Pressure of CO2/Hydrocarbon Systems Within Nanopores

2021 ◽  
Author(s):  
Gang Yang ◽  
Xiaoli Li
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Unconventional Reservoirs ◽  
Minimum Miscibility Pressure ◽  
Theoretical Approaches ◽  
Fluid Systems ◽  
Confined Fluid ◽  
Miscible Gas Injection ◽  
Fluid Characterization ◽  
The Impact

Abstract Minimum miscibility pressure (MMP), as a key parameter for the miscible gas injection enhanced oil recovery (EOR) in unconventional reservoirs, is affected by the dominance of nanoscale pores. The objective of this work is to investigate the impact of nanoscale confinement on MMP of CO2/hydrocarbon systems and to compare the accuracy of different theoretical approaches in calculating MMP of confined fluid systems. A modified PR EOS applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of multiple CO2/hydrocarbon systems at different pore sizes are obtained via the VIT simulations. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the same modified PR EOS is applied to compute the MMP for the same fluid systems. Comparison of these results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, nanoscale confinement results in the drastic suppression of MMP and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

An Experimental Study Investigating the Impact of Miscible and Immiscible Nitrogen Injection on Asphaltene Instability in Nano Shale Pore Structure

2021 ◽  
Author(s):  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Pore Size ◽  
Oil Recovery ◽  
Gas Injection ◽  
Production Costs ◽  
Microscopy Imaging ◽  
Heterogeneous Distribution ◽  
Weight Percentage ◽  
Pore Sizes ◽  
Asphaltene Deposition ◽  
The Impact

Abstract Miscible gas injection has become the most used enhanced oil recovery (EOR) method in the oil and gas industry. The deposition and precipitation of aspahltene during the gas injection process is one of the problems during the oil production process. The asphaltene can deposit and plug the pores, which reduces the permeability in a reservoir; thus, decreasing the oil recovery and increasing the production costs. This research investigates the nitrogen (N2) miscible and immiscible pressure injections on asphaltene instability in shale pore structures . First, a slim-tube was used to determine the minimum miscibility pressure (MMP) of N2to ensure that the effect of both miscible and immiscible gas injection was achievable. Second, filtration experiments were conducted using a specially designed filtration apparatus to investigate the effect of nano pore sizes on asphaltene deposition. Heterogeneous distribution of the filter paper membranes was used in all experiments. The factors studied include miscible/immiscible N2injection and pore size distribution. Visualization tests were conducted to highlight the asphaltene precipitation process over time. The results showed that increasing the pressure increased the asphaltene weight percentage. The miscible N2injection pressure had a significant effect on asphaltene instability. However, the immiscible N2injection pressure had a lower effect on the asphaltene deposition, which resulted in less asphaltene weight percentage. For both miscible/immiscible N2injection pressures, the asphaltene weight percentage increased as the pore size of the filter membranes decreased. Visualization tests showed that after one hour the asphaltene clusters were clearly noticed and suspended in the solvent of heptane, and the asphaltene was fully deposited after 12 hours. Microscopy imaging of filter membranes indicated significant pore plugging from asphaltene, especially for smaller pore sizes.

scholarly journals Study of the impact of injection parameters on the performance of miscible sour gas injection for enhanced oil recovery

2019 ◽  
Vol 10 (4) ◽  
pp. 1575-1589
Author(s):  
Aminu Yau Kaita ◽  
Oghenerume Ogolo ◽  
Xingru Wu ◽  
Isah Mohammed ◽  
Emmanuel Akaninyene Akpan
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Research Work ◽  
Gas Concentration ◽  
Acid Gas ◽  
Minimum Miscibility Pressure ◽  
Injection Parameters ◽  
The Impact ◽  
Sour Gas

AbstractSour gas reservoirs have faced critics for environmental concerns and hazards, necessitating a novel outlook to how the produced sour gases could be either utilized or carefully disposed. Over the years of research and practice, several methods of sour gas processing and utilization have been developed, from the solid storage of sulfur to reinjecting the sour gas into producing or depleted light oil reservoir for miscible flooding enhanced oil recovery. This paper seeks to investigate the impact of injection parameters on the performance of sour gas injection for enhance oil recovery. In designing a miscible gas flooding project, empirical correlations are used and the key parameter which impacts the phase behavior is identified to be the minimum miscibility pressure (MMP). A compositional simulator was utilized in this research work to study the effect of injection parameters such as minimum miscibility pressure, acid gas concentration, injection pressure and injection rate on the performance of miscible sour gas injection for enhanced oil recovery. The findings showed that methane concentration had a significant impact on the MMP of the process. Additionally, an increase in acid gas concentration decreases the MMP of the process as a result of an increase in gas viscosity, consequently extending the plateau period resulting in late gas breakthrough and increased overall recovery of the process.

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^

Use CO2 Soluble Surfactant to Decrease the Minimum Miscibility Pressure of CO2 Flooding in Oil Reservoir

2011 ◽  
Vol 239-242 ◽  
pp. 2650-2654
Author(s):  
Fu Chen ◽  
Jie He ◽  
Ping Guo ◽  
Yuan Xu ◽  
Cheng Zhong
Keyword(s):  
Citric Acid ◽  
Crude Oil ◽  
Water System ◽  
Viscosity Reduction ◽  
Mass Ratio ◽  
Oil Viscosity ◽  
Minimum Miscibility Pressure ◽  
Oil Water ◽  
Carbon Dioxide Miscible Flooding ◽  
Soluble Surfactant

According to the mechanisms of carbon dioxide miscible flooding and previous researchers’ work on synthesis of CO2-soluble surfactant, Citric acid isoamyl ester was synthesized, and it’s oil solubility and the rate of viscosity reduction both in oil-water system and oil were evaluated. And then we found that this compound can solve in oil effectively; the optimum mass of Citric acid isoamyl ester introduced in oil-water system is 0.12g when the mass ratio of oil and water is 7:3 (crude oil 23.4g, formation water 10g) and the experimental temperature is 50°C , the rate of viscosity reduction is 47.2%; during the evaluation of the ability of Citric acid isoamyl ester to decrease oil viscosity, we found that the optimum dosage of this compound in 20g crude oil is 0.2g when the temperature is 40°C, and the rate of viscosity reduction is 7.37% at this point.

Correlation of Crude Oil Steam Distillation Yields With Basic Crude Oil Properties

1983 ◽  
Vol 23 (06) ◽  
pp. 937-945 ◽  
Author(s):  
Ching H. Wu ◽  
Robert B. Elder
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Boiling Point ◽  
Steam Distillation ◽  
Recovery Process ◽  
Steam Injection ◽  
Steam Pressure ◽  
Oil Viscosity ◽  
Simulated Distillation ◽  
Distillation Yield

Abstract Steam distillation can occur in reservoirs during steam injection and in-situ combustion processes. To estimate the amount of vaporized oil caused by steam distillation, we established correlations of steam distillation yields with the basic crude oil properties. These correlations were based on steam distillation tests performed on 16 crude oils from various pans of the U.S. The gravity of oils varied from 12 to 40 deg. API [0.99 to 0.83 g/cm3]. The viscosity of oil ranged from 5 to 4,085 cSt [5 to 4085 mm /s] at 100 deg. F [38 deg. C]. The steam distillations were performed at a saturated steam pressure of 220 psia [1.5 MPa]. One oil sample was used in experiments to investigate the effect of steam pressure (220 to 500 psia [1.5 to 3.4 MPa]) on the steam distillation yield. The experiments were carried out to a steam distillation factor (Vw/Voi) of 20, with the factor defined as the cumulative volume of condensed steam used in distillation, Vw, divided by the initial volume of oil, Voi. At a steam distillation factor of 20, the distillation yields ranged from 13 to 57% of the initial oil volume. Several basic crude oil properties can be used to predict steam distillation yields reasonably well. A correlation using oil viscosity in centistokes at 100 deg. F [38 deg. C] can be used to predict the steam distillation yield within a standard error of 4.3 %. The API gravity can be used to estimate wields within 5.6%. A gas chromatographic analysis was made for each crude oil to obtain the component boiling points (simulated distillation temperatures). A correlation parameter was selected from the simulated distillation results that can be used to estimate the steam distillation yields within 4.5%. Introduction Steamflooding has been used commercially to recover heavy oils for several decades. Although it is considered a heavy-oil recovery process, it has been demonstrated to be an effective and commercially feasible process for recovering light oils. To enhance the effectiveness of the oil recovery process, it is important to fully understand and utilize the basic steamflooding mechanisms. Willman et al. investigated the mechanisms of steamflooding. They concluded that oil viscosity reduction, oil volume expansion, and steam distillation are the major mechanisms for oil recovery. Since then, more research has been done on all phases of steam injection. However, steam distillation and its ramifications on recovery have not been quantified fully because of lack of experimental data. Steam distillation can lower the boiling point of a water/oil mixture below the boiling point of the individual components. SPEJ P. 937^

scholarly journals An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

2019 ◽  
Vol 74 ◽  
pp. 59 ◽  
Author(s):  
Erhui Luo ◽  
Zifei Fan ◽  
Yongle Hu ◽  
Lun Zhao ◽  
Jianjun Wang
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Simulation Method ◽  
Carbonate Reservoir ◽  
Gas Oil ◽  
Oil Composition ◽  
Acid Gas ◽  
Compositional Model ◽  
Injection Process ◽  
Acid Gas Injection

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

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.

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