Investigating and Mitigating Asphaltene Precipitation and Deposition in Low Permeability Oil Reservoirs During Carbon Dioxide Flooding to Increase Oil Recovery

2018 ◽  
Author(s):  
Sherif Fakher ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Low Permeability ◽  
Asphaltene Precipitation ◽  
Carbon Dioxide Flooding

A New Evaluation Way for the Adaptability of CO2 Flooding Reservoirs Based on Cluster Analysis

2014 ◽  
Vol 962-965 ◽  
pp. 457-460 ◽  
Author(s):  
Jing Jie Yao ◽  
Zhi Ping Li ◽  
Yang Chen
Keyword(s):  
Carbon Dioxide ◽  
Cluster Analysis ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Displacement Effect ◽  
Oil Displacement ◽  
Advanced Analysis ◽  
Carbon Dioxide Miscible Flooding ◽  
Carbon Dioxide Flooding ◽  
General Method

Carbon dioxide miscible flooding in oil reservoirs is a general method of enhancing oil recovery, nevertheless, not all reservoirs adapt to this method. Therefore, evaluating the adaptability of carbon dioxide flooding reservoirs becomes an important problem which is urged to be solved. Through the research of carbon dioxide flooding situation and displacement mechanism, twelve factors which influenced the oil displacement effect could be obtained. Compared factors with oil recovery by means of the advanced analysis of SPSS, and chose ten factors to be the evaluating indices which could apply in cluster analysis. Through building mathematical model and clustering reservoirs, the adaptability of carbon dioxide flooding could be evaluated comprehensively. Apply this method to cluster nine typical reservoirs which have adopted carbon dioxide flooding, the results show that, this method can evaluate the adaptability of carbon dioxide flooding reservoirs, which is corresponding to the real exploitation effect.

The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery

2004 ◽  
Vol 126 (2) ◽  
pp. 119-124 ◽  
Author(s):  
O. S. Shokoya ◽  
S. A. (Raj) Mehta ◽  
R. G. Moore ◽  
B. B. Maini ◽  
M. Pooladi-Darvish ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Cost Effective ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Flue Gases ◽  
Low Permeability ◽  
Light Oil ◽  
Light Oil Reservoirs

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.

scholarly journals Study on Prevention of Gas Channelling of Acid-resistant Gel Foam in CO2 Flooding of Low Permeability Reservoir

2020 ◽  
Vol 194 ◽  
pp. 01041
Author(s):  
Zhaoxia LIU ◽  
Ming GAO ◽  
Shanyan ZHANG ◽  
Wanlu LIU
Keyword(s):  
Oil Recovery ◽  
Retention Rate ◽  
Crosslinking Agent ◽  
Water Soluble ◽  
Oil Reservoirs ◽  
Low Permeability ◽  
Co2 Flooding ◽  
Water Separation ◽  
Co2 Gas ◽  
Low Permeability Reservoirs

With the shortage of recoverable reserves in conventional oil reservoirs, the development of low-permeability oil reservoirs has received more and more attention. The oil recovery of low-permeability reservoirs can be significantly improved by CO2 flooding, as it can effectively supply formation energy. CO2 flooding is an effective technology for increasing oil production in low-permeability reservoirs. However, because of the heterogeneity of the reservoir and the effect of natural fractures, CO2 gas channelling easily occurs during CO2 flooding, seriously reducing CO2 flooding effect. In this study, the gas channelling technology of acid-resistant gel foam was investigated. Preferred acid-resistant gel foam system formula was found as 0.1% by mass of AOS foaming agent with 0.3% to 0.4% by mass of instant HPAM polymer and 1% to 2% by mass of water-soluble phenolic resin crosslinking agent. This system still has a good foaming ability and blocking performance under at pH=2 and a salinity of 10×104 mg/L. After 60 days of aging under oil reservoir conditions, there is no obvious water separation, and the plugging strength retention rate reached more than 60%. The gel foam channelling system can be applied to highly heterogeneous and low permeability reservoirs with a permeability gradient higher than 14 and can increase the recovery rate by more than 20% based on the CO2 flooding. Acid-resistant gel foam channelling technology can effectively inhibit CO2 gas channelling and improve CO2 flooding effect in low permeability reservoirs.

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.

Modeling Formation Damage by Asphaltene Deposition During Primary Oil Recovery

2005 ◽  
Vol 127 (4) ◽  
pp. 310-317 ◽  
Author(s):  
Shaojun Wang ◽  
Faruk Civan
Keyword(s):  
Experimental Data ◽  
Mathematical Model ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Formation Damage ◽  
Asphaltene Precipitation ◽  
Vertical Wells ◽  
Core Flow ◽  
Asphaltene Deposition

Asphaltene precipitation and deposition during primary oil recovery and resulting reservoir formation damage are described by a phenomenological mathematical model. This model is applied using experimental data from laboratory core flow tests. The effect of asphaltene deposition on porosity, permeability, and the productivity of vertical wells in asphaltenic-oil reservoirs are investigated by simulation.

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