Asphaltene stability in crude oil during carbon dioxide injection and its impact on oil recovery: A review, data analysis, and experimental study

Crude oils are usually associated with many compounds, some of which are favorable and others, which are not. One of the most unfavorable components of crude oil that pose severe operational problems and decreases oil production significantly are asphaltenes. These compounds are solids that are homogenized in the crude oil at room temperature but tend to separate from solution when agitated. They can deposit in the reservoir pores, wellbore, and transportation pipelines thus causing severe operational problems and oil recovery reduction. Even though researchers have been studying asphaltenes for more than 100 years, there is still an ambiguity concerning asphaltene structure and characteristics since asphaltenes have no unique structure. This research performed a comprehensive data analysis on both laboratory studies and field cases involving asphaltene in order to provide a generalized guideline on asphaltene properties asphaltene stability. The analysis was based on more than 200 references involving more than 4000 experiments and 19 field studies. Two statistical analysis tools were used, including histograms and boxplots. After determining the factor impacting asphaltene, this research conducted experiments to understand the impact of these factors on asphaltene stability in crude oil during carbon dioxide (CO2) injection in unconventional shale nanopores, since very limited research has been conducted in this area. The research investigated the impact of several factors including pressure, temperature, oil viscosity, pore size, porous media thickness, and heterogeneity on asphaltene precipitation, pore plugging, and oil recovery reduction. A Pareto Plot was also generated to determine the factor that had the strongest impact on asphaltene instability in the crude oil --Abstract, page iv

Investigating the factors impacting the success of immiscible carbon dioxide injection in unconventional shale reservoirs: An experimental study

Unconventional shale reservoirs are currently gaining significant interest due to the huge hydrocarbon volumes that they bear. Enhanced oil recovery (EOR) techniques have been suggested to increase recovery from shale reservoirs. One of the most promising EOR methods is gas EOR (GEOR), most notably carbon dioxide (CO2). Not only can CO2 increase oil recovery by interacting with the oil and the shale, but it has also been shown to adsorb to the shale rock and thus is effective in both EOR applications and also carbon storage purposes. This research aims to experimentally investigate several of the interactions that may impact CO2 injection in shale reservoirs in hopes of defining and quantifying the factors impacting these interactions and how these factors can contribute to an improvement in oil recovery from these reservoirs. This research begins by undergoing a review and data analysis on immiscible CO2 injection to investigate its injection methods, mechanisms, governing equations, and factors influencing its applicability. Following this, a mathematical simulation was undergone to investigate the different CO2 flow regimes that could occur during CO2 injection in shale reservoirs. The interaction of the CO2 with the shale rock via adsorption was investigated by undergoing several adsorption experiments. The CO2 interaction with the oil was also investigated by undergoing oil swelling which is considered the main mechanism by which oil recovery can be increased during immiscible CO2 injection, and asphaltene experiments to investigate the factors impacting these two interactions. Finally, cyclic CO2 injection was performed to determine the oil recovery potential of GEOR from shale reservoirs --Abstract, page iv

A Review of Carbon Dioxide Adsorption to Unconventional Shale Rocks Methodology, Measurement, and Calculation

Carbon dioxide (CO2) injection has been applied extensively in hydrocarbon reservoirs for both increasing oil recovery and CO2 storage purposes. Recently, CO2 injection has been proposed to increase oil recovery and for CO2 storage in shale reservoirs. During CO2 injection in shale reservoirs, adsorption will take place on the surface of the rock, which will impact both the oil recovery and the storage capacity. This research provides a roadmap to the different types of adsorption and the adsorption measurements and calculations with emphasis on the ones most applicable during CO2 injection in shale reservoirs. The main two types of adsorption are initially explained including physisorption and chemisorption, and the major applicable adsorption isotherms are explained and their limitations are listed. The research then focusses on physisorption and its types, and hysteresis trends since chemisorption does not occur in shale reservoirs during CO2 injection. The different methods used to measure adsorption are then illustrated and explained including volumetric, gravimetric, volumetric-gravimetric, oscillometry, and impedance spectroscopy. The different calculation methods for volumetric adsorption are then explained. Finally, the most common errors that have been observed during measurement and calculation of adsorption are listed and explained, while mentioning the method to avoid each error. This research provides a guideline to the proper and accurate measurement of CO2 adsorption on shale rock during enhanced oil recovery applications and CO2 storage operations in unconventional shale reservoirs to improve the productivity and applicability of this application

A Data Analysis of Immiscible Carbon Dioxide Injection Applications for Enhanced Oil Recovery based on an Updated Database

Carbon dioxide (CO2) injection is an enhanced oil recovery technique used worldwide to increase oil recovery from hydrocarbon reservoirs. Immiscible CO2 injection involves injecting the CO2 into the reservoir at a pressure below which it will become miscible in the oil. Even though immiscible CO2 injection has been applied extensively, very little research has been conducted to provide a comprehensive understanding of the mechanism and the applications of immiscible CO2 injection. This research performs an in-depth data analysis is performed based on more than 200 experiments and 20 field tests from more than 40 researches to show the conditions at which immiscible CO2 injection has been applied and the most frequent application conditions. Histograms and boxplots have been generated for temperature, CO2 injection pressure, oil viscosity, molecular weight, and API gravity, CO2 solubility, and finally oil swelling to show the ranges and frequency of application for all these parameters. Finally, crossplots have been generated from the data to show the relation of pressure and temperature to CO2 solubility and oil swelling. The crossplots function to illustrate a relation between the variables and draws a conclusion as to what effect each parameter will have on the other

A Simplified Method for Experimentally Quantifying Crude Oil Swelling during Immiscible Carbon Dioxide Injection

Immiscible carbon dioxide (CO2) injection is one of the highly applied enhanced oil recovery (EOR) methods due to its high oil recovery potential and its ability to store CO2 in the reservoir. The main mechanism of immiscible CO2 injection is oil swelling. Generally, oil swelling is measured experimentally or measured using modeling methods. This research conducts oil swelling experiments using a simplified method in order to easily and accurately measure oil swelling and determines some of the most significant factors that may impact oil swelling during CO2 injection. The impact of varying CO2 injection pressure, temperature, oil viscosity and oil volume on oil swelling capacity was investigated. The simplified method managed to accurately determine the value of oil swelling for all the experiments. One of the factors that was found to impact the method significantly was the oil volume used. The oil volume in the experimental vessel was found to be extremely important since a large oil volume may result in a false oil swelling value. The oil swelling results were compared to other researches and showed that the method applied had an accuracy of over 90% for all the results obtained. This research introduces a simple method that can be used to measure oil swelling and applies this method to investigate some of the factors that may impact the oil swelling capacity during immiscible CO2 injection

Flow of Carbon Dioxide in Micro and Nano Pores and its Interaction with Crude Oil to Induce Asphaltene Instability

This study presents an investigation of the flow mechanism of carbon dioxide (CO2) through nano and micro pores and the impact of this flow on oil mobilization and asphaltene instability in the crude oil. The flow mechanism of CO2 is determined using numerical modeling through the Knudsen number to determine the flow regimes under different thermodynamic conditions. Following this, the oil production and asphaltene stability are studied using a filtration vessel supplemented with nano and micron sized filter membranes. The effect of varying CO2 injection pressure, oil viscosity, porous media pore size, and porous media thickness on oil mobilization and asphaltene stability are studied. Regarding the flow regimes, it is found that four distinct flows are observed during CO2 injection in the nano and micro pores. These flow regimes included diffusion, transition, slippage, and viscous flow. As the pore size increases, the flow becomes viscous dominated. Crude oil flow through the nano pores required higher pressure and also resulted in more severe asphaltene damage and plugging compared to the micro pores. Increasing the CO2 injection pressure increased oil production and decreased the asphaltene concentration in the bypassed crude oil, which is the oil remaining in the filtration vessel and could not be produced. The lower oil viscosity is associated with a lower asphaltene concentration and thus yields an overall higher oil viscosity as well. By undergoing this research, a better understanding of how the CO2 flows through nano and micro pores can be achieved, and oil mobilization and asphaltene instability with time can also be understood

Critical Review of Asphaltene Properties and Factors Impacting its Stability in Crude Oil

Asphaltene is a component of crude oil that has been reported to cause severe problems during production and transportation of the oil from the reservoir. It is a solid component of the oil that has different structures and molecular makeup which makes it one of the most complex components of the oil. This research provides a detailed review of asphaltene properties, characteristics, and previous studies to construct a guideline to asphaltene and its impact on oil recovery. The research begins with an explanation of the main components of crude oil and their relation to asphaltene. The method by which asphaltene is quantified in the crude oil is then explained. Due to its different structures, asphaltene has been modeled using different models all of which are then discussed. All chemical analysis methods that have been used to characterize and study asphaltene are then mentioned and the most commonly used method is shown. Asphaltene will pass through several phases in the reservoir beginning from its stability phase up to its deposition in the pores, wellbore, and facilities. All these phases are explained, and the reason they may occur is mentioned. Following this, the methods by which asphaltene can damage oil recovery are presented. Asphaltene rheology and flow mechanism in the reservoir are then explained in detail including asphaltene onset pressure determination and significance and the use of micro- and nanofluidics to model asphaltene. Finally, the mathematical models, previous laboratory, and oilfield studies conducted to evaluate asphaltene are discussed. This research will help increase the understanding of asphaltene and provide a guideline to properly study and model asphaltene in future studies

An Experimental Investigation of Asphaltene Stability in Heavy Crude Oil during Carbon Dioxide Injection

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\u27s 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

A Characterization of Different Alkali Chemical Agents for Alkaline Flooding Enhanced Oil Recovery Operations: An Experimental Investigation

Alkaline injection is a chemical enhanced oil recovery method that is used to increase oil recovery by reacting with the crude oil and creating an in situ surfactant. Many chemical agents can be used as an alkali during injection all of which have several advantages and disadvantages. This research focuses on the innate properties of three alkali agents and their ability to alter pH and temperature downhole. Alkali solutions were prepared with five different concentrations including 0.2, 1, 2, 3, and 4 wt%. The impact of varying the alkali concentration, monovalent cations manifested in sodium chloride, and divalent cations manifested in calcium chloride was investigated for all three alkalis. The chemical agents investigated include sodium hydroxide, sodium silicate, and sodium carbonate. Results indicated that sodium hydroxide and sodium silicate managed to impact the pH the most compared to the sodium carbonate. Sodium hydroxide also managed to increase the temperature significantly which is advantageous since it can reduce oil viscosity downhole. Sodium silicate had an advantage of being in liquid state at ambient conditions which makes injecting it downhole much easier compared to the two other alkaline agents. The chemical that was much affected by divalent cations was sodium silicate, which generated a precipitate and thus is not compatible with divalent cations, which are a major composition of most formation water. This research focuses on the innate properties of the alkali agents and the downhole factors that may impact their applicability in different oil reservoirs

Gas Slippage in Tight Formations

In order to address the gas slippage for flow through tight formation, with a very low porosity (less than 10%) and permeability in micro-Darcy range, a series of single-phase gas flow experiments were conducted. Two different gases (N2 and He) were used to carry out many single-phase experiments at different overburden and pressure drops and were compared with carbon dioxide (CO2) flow types. The pore size distribution measurements showed the existence of a wide range of pore size distribution. Also, the single-phase gas flow experiments through the core plug, mostly at low pressure, showed Knudsen diffusion type, which is an indication of gas molecules’ slippage at the wall of the pores