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Investigation of Mechanisms Responsible for Enhanced Oil Recovery

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (4 January 2021) | Viewed by 14248

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Dr. Jan Vinogradov

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School of Engineering, King's College, University of Aberdeen, Aberdeen AB24 3UE, UK
Interests: multi-phase flow in porous media; application of self-potential to subsurface flow monitoring; rock wettability characterisation; CGS; EOR
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Special Issue Information

Dear Colleagues,

Increasing global demand for energy sources combined with a relatively low oil recovery factor using conventional methods, promotes extensive research into enhanced oil recovery (EOR) methods. Although conventional chemical (alkaline, surfactant and polymer) injection methods have been deployed for over two decades, other methods such as smart water and miscible gas injection, various thermal methods, use of nano-materials and ultrasonic technology are still being matured. The main challenge in applying different EOR methods has always been associated with limited understanding of the underlying mechanisms responsible for improved oil recovery. Experimental data obtained from coreflooding tests on clastic and carbonate rocks are scarce and the results are sometimes inconsistent and even contradicting. On the other hand, numerical simulations performed on length scales ranging from nanometers to kilometers and employing pore network, molecular dynamic and conventional reservoir simulation methods still encounter challenges related to upscaling procedures, inconsistent description of rock properties across different scales, and eventually lack the ability to accurately describe and predict gains from applied EOR methods.

This Special Issue is therefore inviting papers on recent advancements in various EOR methods. The Special Issue welcomes papers reporting experimental studies on multiple scales as well as numerical and theoretical works that focus on explaining the complex underlying mechanisms of well-established and novel EOR methods.

Dr. Jan Vinogradov
Guest Editor

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Keywords

EOR methods in carbonate and sandstone reservoirs
Conventional chemical and thermal EOR methods
Miscible gas and smart water injection EOR
Nano-particles, microwave, ultrasonic technology
Experimental, numerical and theoretical investigation of EOR mechanisms
Pore- to reservoir-scale EOR simulations

Published Papers (6 papers)

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Research

20 pages, 6044 KiB

Open AccessArticle

Simulation-Based Optimization of Microbial Enhanced Oil Recovery with a Model Integrating Temperature, Pressure, and Salinity Effects

by Moon Sik Jeong, Young Woo Lee, Hye Seung Lee and Kun Sang Lee

Energies 2021, 14(4), 1131; https://doi.org/10.3390/en14041131 - 20 Feb 2021

Cited by 10 | Viewed by 1843

Abstract

The microbial enhanced oil recovery (MEOR) method is an eco-friendly and economical alternative technology. The technology involves a variety of uncertainties, and its success depends on controlling microbial growth and metabolism. Though a few numerical studies have been carried out to reduce the uncertainties, no attempt has been made to consider temperature, pressure, and salinity in an integrated manner. In this study, a new modeling method incorporating these environmental impacts was proposed, and MEOR analysis was performed. As a result, accurate modeling was possible to prevent overestimating the performance of MEOR. In addition, oil recovery was maximized through sensitivity analysis and optimization based on an integrative model. Finally, applying MEOR to an actual reservoir model showed a 7% increase in oil recovery compared to waterflooding. This result proved the practical applicability of the method. Full article

(This article belongs to the Special Issue Investigation of Mechanisms Responsible for Enhanced Oil Recovery)

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16 pages, 3726 KiB

Open AccessArticle

Controlled Salinity-Biosurfactant Enhanced Oil Recovery at Ambient and Reservoir Temperatures—An Experimental Study

by Tinuola Udoh and Jan Vinogradov

Energies 2021, 14(4), 1077; https://doi.org/10.3390/en14041077 - 18 Feb 2021

Cited by 4 | Viewed by 2031

Abstract

In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme^® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relative to injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 °C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs. Full article

(This article belongs to the Special Issue Investigation of Mechanisms Responsible for Enhanced Oil Recovery)

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14 pages, 5484 KiB

Open AccessArticle

System of Comprehensive Energy-Efficient Utilization of Associated Petroleum Gas with Reduced Carbon Footprint in the Field Conditions

by Valentin Morenov, Ekaterina Leusheva, George Buslaev and Ove T. Gudmestad

Energies 2020, 13(18), 4921; https://doi.org/10.3390/en13184921 - 19 Sep 2020

Cited by 21 | Viewed by 2619

Abstract

This paper considers the issue of associated petroleum gas utilization during hydrocarbon production in remote petroleum fields. Due to the depletion of conventional oil and gas deposits around the globe, production shifts to hard-to-recover resources, such as heavy and high-viscosity oil that requires a greater amount of energy to be recovered. At the same time, large quantities of associated petroleum gas are extracted along with the oil. The gas can be utilized as a fuel for power generation. However, even the application of combined power modes (combined heat and power and combined cooling heat and power) cannot guarantee full utilization of the associated petroleum gas. Analysis of the electrical and heat loads’ graphs of several oil fields revealed that the generated thermal energy could not always be fully used. To improve the efficiency of the fuel’s energy potential conversion, an energy system with a binary power generation cycle was developed, consisting of two power installations—a main gas microturbine and an auxiliary steam turbine unit designed to power the technological objects in accordance with the enterprise’s power load charts. To provide for the most complete utilization of associated petroleum gas, a gas-to-liquid system is introduced, which converts the rest of the gas into synthetic liquid hydrocarbons that are used at the field. Processing of gas into various products also lowers the carbon footprint of the petroleum production. Application of an energy system with a binary power generation cycle makes it possible to achieve an electrical efficiency up to 55%, at the same time maintaining high efficiency of consumers’ energy supply during the year. The utilization of the associated petroleum gas in the developed system can reach 100%. Full article

(This article belongs to the Special Issue Investigation of Mechanisms Responsible for Enhanced Oil Recovery)

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23 pages, 7781 KiB

Open AccessArticle

Simulation of Immiscible Water-Alternating-CO₂ Flooding in the Liuhua Oilfield Offshore Guangdong, China

by Gang Hu, Pengchun Li, Linzi Yi, Zhongxian Zhao, Xuanhua Tian and Xi Liang

Energies 2020, 13(9), 2130; https://doi.org/10.3390/en13092130 - 28 Apr 2020

Cited by 8 | Viewed by 2709

Abstract

In this paper, the immiscible water-alternating-CO₂ flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO₂ injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO₂ injection (Con-CO₂) and primary depletion production (No-CO₂) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO₂ WAG over both Con-CO₂ and No-CO₂ scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO₂ injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO₂ injection volume, the CO₂ storage efficiency is still high, more than 84% of the injected CO₂ was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO₂ processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO₂ enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project. Full article

(This article belongs to the Special Issue Investigation of Mechanisms Responsible for Enhanced Oil Recovery)

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22 pages, 9799 KiB

Open AccessArticle

Effect of Pore Size Heterogeneity on Hydrocarbon Fluid Distribution, Transport, and Primary and Secondary Recovery in Nano-Porous Media

by Kaiyi Zhang, Fengshuang Du and Bahareh Nojabaei

Energies 2020, 13(7), 1680; https://doi.org/10.3390/en13071680 - 03 Apr 2020

Cited by 2 | Viewed by 2177

Abstract

In this paper, we investigate the effect of pore size heterogeneity on fluid composition distribution of multicomponent-multiphase hydrocarbons and its subsequent influence on mass transfer in shale nanopores. The change of multi-contact minimum miscibility pressure (MMP) in heterogeneous nanopores was investigated. We used a compositional simulation model with a modified flash calculation, which considers the effect of large gas–oil capillary pressure on phase behavior. Different average pore sizes for different segments of the computational domain were considered and the effect of the resulting heterogeneity on phase change, composition distributions, and production was investigated. A two-dimensional formulation was considered here for the application of matrix–fracture cross-mass transfer and the rock matrix can also consist of different segments with different average pore sizes. Both convection and molecular diffusion terms were included in the mass balance equations, and different reservoir fluids such as ternary mixture syntactic oil, Bakken oil, and Marcellus shale condensate were considered. The simulation results indicate that oil and gas phase compositions vary in different pore sizes, resulting in a concentration gradient between the two adjacent pores of different sizes. Given that shale permeability is extremely small, we expect the mass transfer between the two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix–fracture component mass transfer as a result of confinement-dependent phase behavior. Therefore, the molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection enhanced oil recovery (EOR) simulation of heterogeneous shale reservoirs. Full article

(This article belongs to the Special Issue Investigation of Mechanisms Responsible for Enhanced Oil Recovery)

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21 pages, 19703 KiB

Open AccessArticle

Controls on Reservoirs Quality of the Upper Jurassic Mengyin Formation Sandstones in Dongying Depression, Bohai Bay Basin, Eastern China

by Shaochun Yang, Ya Wang, Shiqi Zhang, Yongchao Wang, Yifan Zhang and Yongfu Zhao

Energies 2020, 13(3), 646; https://doi.org/10.3390/en13030646 - 03 Feb 2020

Cited by 4 | Viewed by 2324

Abstract

The Upper Jurassic Mengyin Formation sandstones are important targets for petroleum exploration in Dongying Depression of Bohai Bay Basin, Eastern China. Although the current burial depth of the Upper Jurassic Mengyin Formation sandstones is shallow (900–2500 m), the reservoir rocks are characterized by low porosity and low permeability due to the complex diagenetic modifications after deposition. Experimental tests and statistical methods, such as thin section, scanning electron microscopy (SEM), cathodoluminescence (CL), high pressure mercury injection (HPMI) and fluid inclusion analysis are conducted to delineate the mineralogical, petrographic and petro-physical characteristics. Results show that physical and chemical processes, including burial depth, burial and thermal history and pore fluid evolution, are both important for the diagenetic modifications that result in a variety changes in pore system and reservoir quality. According to numerical simulation of porosity evolution during lengthy burial and thermal history, porosity loss due to the early deep burial process under the high paleo-geothermal gradient can reach about 20%. Moreover, the burial history (effective stress and temperature) has a better guidance to reservoir quality prediction compared with current burial depth. The extensive compaction in sandstones also resulted in extremely low pore fluid flow during subsequent diagenetic processes, thus, the reaction products of dissolution cannot be removed, which would be precipitated as carbonate cements during stable reburial phase. Dissolution resulted from uncomformity-related meteoric flushing have been the most important porosity-enhancing factor in Mengyin Formation sandstones in spite of low thin section porosity averaged out to 3.22%. Secondary pores derived from dissolution of unstable silicates are more likely to develop in sandstones near the regional unconformity. The oil source fault activities may enhance the heterogeneity of reservoir rocks and control the reservoir quality by inducing micro-fractures and providing the main pathways for hydrocarbon migration. Full article

(This article belongs to the Special Issue Investigation of Mechanisms Responsible for Enhanced Oil Recovery)

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