Heavy Oil Reserves Research Articles

Governing chemical reactions and mechanisms of hydrogen generation during in-situ combustion gasification of heavy oil

The global push for sustainable energy solutions has highlighted the importance of producing carbon-zero hydrogen (H2) directly from petroleum reservoirs. In-situ combustion gasification (ISCG) presents a groundbreaking method to harness the potential of heavy oil reserves for clean hydrogen production. Although simulations have demonstrated the considerable promise of ISCG, the key reactions controlling hydrogen generation require experimental validation, and the underlying mechanisms remain largely unexplored. This research aims to describe the chemical reactions and mechanisms responsible for hydrogen generation during the ISCG of heavy oil. Using a specially designed kinetic cell, we conducted combustion and gasification experiments with heavy oil and coke. The findings revealed that clay minerals in the reservoir sand act as catalysts in the oxidation reactions of heavy oil by shifting reactions to lower temperatures by approximately 20 °C. Hydrogen production began at 450 °C and peaked at 900 °C, with coke gasification and the water-gas shift reaction being the primary mechanisms. Additionally, methane was produced due to hydrogen consumption via methanation reactions, and minerals in the reservoir sands were found to inhibit hydrogen production by increasing hydrogen consumption and methane generation at temperatures above 800 °C. Controlling the reservoir temperature within an optimal range between 450 and 800 °C can enhance hydrogen generation by managing the process mechanisms. This study provides a detailed examination of the ISCG process for heavy oil, paving the way for future development of kinetic models to simulate hydrogen production through ISCG. It also emphasizes the significance of mechanistic control in enhancing hydrogen generation and suppressing hydrogen consumption reactions.

Stability of THAI in situ combustion process in reservoirs with layers of grading permeabilities and porosities: Detailed qualitative investigations

The world-wide reserves of heavy oil, tar sand, and bitumen, etc., outweigh those of conventional oil by a factor of 7/3. Given that the conventional reserves are being rapidly depleted, the need to develop and produce the unconventional resources has never been so critical. However, the proven most efficient and environmentally-friendly technology, namely the THAI process, still requires further study, and it has no documented design procedures that factor in the non-ideal geological features of heavy oil and bitumen reservoirs. Throughout the literature, there is little reported on the effects of gradations in reservoir petro-physical parameters on the performance of the THAI process. Consequently, this work reports the results of numerical simulations for four different kinds of reservoirs, each having progressive gradations in permeabilities and porosities. The major findings from this in depth study include.(i) In terms of the temperature distribution, regardless of the permeability and porosity gradations, the high temperature zone is always skewed towards the highest permeabilities and porosities zone. Furthermore, it is found that, in any model in which the shoes of the VI wells have no direct communication pathway with the highest permeabilities and porosities zones of the reservoirs, the high temperature zones occur in two chambers, otherwise, there is one high temperature zone.(ii) It is found that generally, the combustion front tends to be lopsided in favour of the most permeable and porous zone. In the case of a bottom-up progressive increase in permeabilities and porosities (model L1), the single combustion front has greatest advance horizontally at the top and axially in the middle of the reservoir, while in model L2 (the converse of model L1), the combustion fronts propagated in two chambers before the chambers overlapped in the toe region of the HP well where it advanced fastest. Therefore, the combustion zone in model L1 was far more stable than in model L2.(iii) It is found that the combustion fronts in model L3, with the lowest permeabilities and porosities at the centre in the longitudinal direction, propagated in two chambers that overlapped each other around the toe region of the HP well and advanced greatest in the HP well and on either lateral edge of the reservoir. In model L4, which has lateral gradation in permeabilities and porosities, however, the thinner edge of the wedge-shape combustion front had advanced fastest along the vertical mid-plane where the HP well was located. Thus, the combustion zone in model L3 was far more stable than that in model L4.(iv) It is found that in all the models except model L4, there exist rich oil saturation zones in the most permeable and porous regions located ahead of the mobile oil zone (MOZ) of each reservoir. These are formed due to restrictions in the pathways via which the mobilised oil can drain into the HP well. In model L4, the HP well is already in the most permeable zone and consequently, the fluids that favourably reach there are rapidly gravity-drained into the HP well.

Analysis of Adaptability and Application Potential of Supercritical Multi-Source Multi-Component Thermal Fluid Technology for Offshore Heavy Oil in China

Supercritical multi-source, multi-component thermal fluid is a heavy oil thermal recovery method independently developed by China National Offshore Oil Co., Ltd (Beijing, China). It uses waste liquid at the production end of the production well as the water source, the injection medium temperature exceeds 374 °C, 22.1 MPa, and all the produced flue gas is re-injected. Compared with steam huff and puff technology, supercritical technology has the advantages of high enthalpy value, high heat utilization rate, good oil displacement effect, and being green and pollution-free. In addition, its oil–water treatment cost is low, it can realize the reuse of organic matter, it has a good cost advantage of water treatment under the background of low carbon, and it is a thermal recovery method with great application potential for offshore heavy oil. Therefore, it is necessary to carry out research on the adaptability and application potential of supercritical multi-source, multi-heat flow thermal recovery technology in the sea. Based on the laboratory one-dimensional displacement experiment, this paper reveals the mechanism of heavy oil supercritical multi-source multi-component thermal fluid displacement and the contribution of supercritical components to the displacement effect, and establishes the supercritical multi-source, multi-component thermal fluid numerical simulation characterization method. Combined with the characteristics of offshore heavy oil reserves, the main control factors affecting supercritical multi-source, multi-component thermal fluid development were established by numerical simulation and orthogonal test methods, and the adaptive screening method of offshore supercritical technology was established. The application potential of 670 million tons of offshore heavy oil reserves was evaluated and sorted, and KL 10-2 oilfield was selected as the pilot test oilfield. The results show that supercritical technology has great advantages in oil displacement and water treatment cost reduction, and the results play an important guiding significance for the development of offshore heavy oil technology system and the iteration of new technology.

Combining Steam and Flue Gas as a Strategy to Support Energy Efficiency: A Comprehensive Review of the Associated Mechanisms.

Conventional steam injection projects have long been an iconic process in the development of heavy oil reserves; nevertheless, they face significant challenges in terms of energy efficiency, environmental compliance, and economic viability. Factors such as oil price fluctuations, the imperative for an energy transition, and the push to reduce carbon footprints are hindering new or ongoing implementations of traditional steam injection technologies. In response to these challenges, hybrid methods, such as the combination of steam and flue gas, are emerging as an opportunity to optimize thermal processes to improve oil recovery, energy efficiency, and environmental sustainability and extend reservoir productivity life. Steam injection enhances oil recovery by reducing the viscosity of crude oil, improving oil mobility and facilitating its extraction. The utilization of flue gas in steam injection processes has a significant impact on oil recovery and energy efficiency, leveraging industrial byproducts. This not only lowers operating costs but also reduces environmental emissions, aligned with energy transition trends. Incorporating the flue gas into a steam-based process in heavy oil reservoirs has emerged as a promising thermally enhanced oil recovery strategy. This work presents a comprehensive review based on experimental, numerical, and field studies of hybrid steam and flue gas technology as an EOR process. The main recovery mechanisms associated with the process are analyzed. In addition, the laboratory equipment required for experimental evaluations is presented, and reservoir modeling, kinetic and compositional effects on reservoir fluids, and the reduction in heat losses in the steam injection process are discussed. Furthermore, field implementations are reviewed to evaluate lessons learned and experiences on an operative scale. The combination of steam and flue gas represents an opportunity for carbon utilization and geological carbon sequestration. This dual functionality underscores its potential to enhance oil recovery and address carbon-related environmental concerns.

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Structuring and preliminary selection of enhanced oil recovery methods for the current reservoir conditions of Block C2N, Joint Venture Petrovictoria (Venezuela)

Global heavy oil reserves are the largest hydrocarbon resource in the world, with Venezuela's heavy oil reserves accounting for 87% of initial oil reserves; 258.3 out of 297.7 billion barrels. Primary oil production from such formations does not allow achieving a high recovery factor, which is only 5 to 10% due to the high viscosity of the reservoir oil and low mobility. The main purpose of the work is to determine the hierarchy and, with its help, preliminary selection of enhanced oil recovery (EOR) methods for the current reservoir conditions of the Carabobo 2 North block of the Petrovictoria joint venture, Venezuela. The methodology for selecting promising enhanced oil recovery methods for the created geological model of one of the objects for the potential application of enhanced oil recovery (EOR) methods in Venezuela (Orinoco Belt, Carabobo 2 North Block) is formed using applicability criteria. An EOR for an object based on the theory of fuzzy sets is proposed and evaluated. The main purpose of the work is to create a hierarchy and preliminary selection of methods for increasing oil recovery for the current conditions of the formation of the Carabobo 2 North block of the Petrovictoria joint venture, Venezuela. The method of selection (screening) of promising methods of increasing oil recovery for the created geological model of one of the objects of potential application of the Venezuelan EOR (North, Orinoco Belt), formed using the criteria of applicability and selection of the most promising EOR for the object, based on the theory of fuzzy sets, is presented and tested Keywords: heavy oil; enhanced oil recovery (EOR); EOR selection (screening); Orinoco Belt.

Development of a heat-penetration criterion to characterize steam chamber growth and propagation dynamics during a steam-assisted gravity drainage (SAGD) process

Steam chamber growth and propagation dynamics dictates the success of a steam-assisted gravity drainage (SAGD) process, which is an enhanced oil recovery (EOR) method for effectively and efficiently exploiting the enormous heavy oil and bitumen reserves. To set the baseline, this work is focused on the SAGD process with pure steam. After numerous trials and errors, a heat-penetration criterion has been developed and integrated into a reservoir simulator for the first time to characterize steam chamber growth and propagation dynamics conditioned to the production profiles during a steam-assisted gravity drainage process. More specifically, based on the heat transfer principle, a pore-scale heat-penetration criterion has been developed with respect to both heat conduction and convection for calibrating the temperature distributions ahead of the steam chamber interface (SCI). Subsequently, such a heat-penetration criterion has been upscaled to a grid-scale for its integration with a commercial reservoir simulator (i.e., CMG STARS), allowing us to pragmatically and accurately quantify the dynamic temperature field during a steam-assisted gravity drainage process. Furthermore, three sets of multiphase relative permeabilities are employed to evaluate comprehensive impacts of the thermally sensitive co/counter-current flows. Finally, such a heat-penetration criterion has been verified by reproducing the experimentally measured steam chamber during a steam-assisted gravity drainage process from a large-scale 3D physical model. With such an integrated method, good agreements between the measured and simulated data including production profiles and temperature distributions have been found, whereas the dynamics of production profiles and corresponding steam chamber propagations cannot be well reproduced solely with a commercial reservoir simulator. Sensitivity analysis has been performed to examine the effects of thermal-sensitive properties, steam chamber configuration, boundary, multiphase flow behaviour (e.g., co-current and counter-current flow), and gridblock dimension. In practice, the newly developed heat-penetration criterion can be seamlessly integrated with a commercial reservoir simulator. Such an integrated method can significantly reduce the model complexities and uncertainties, providing a simple and convenient way to dynamically and accurately characterize the steam chamber growth and propagation dynamics within a unified, consistent, and efficient framework.

Reducing CO2 emissions and improving oil recovery through silica aerogel for heavy oil thermal production

Heavy oil reserves comprise more than 60% of global crude oil resources, and thermal oil recovery techniques, especially steam injection, are widely utilized for extracting heavy oil. However, these thermal production processes are characterized by high energy consumption and carbon emissions, which pose significant challenges in reducing CO2 emissions. In response to these challenges, this study presents a novel approach that combines silica aerogel with CO2-assisted thermal recovery technology. Our findings demonstrate that the incorporation of aerogel nanoparticles enhances the adsorption capacity of CO2 in the aqueous phase. The adsorption behavior of CO2 in silica aerogel aligns with the Langmuir model. When silica aerogel nanoparticles are employed in steam flooding, a notable improvement is observed in both oil recovery and CO2 sequestration rate. Molecular dynamics simulations reveal that the porous structure of aerogel enables the adsorption of light saturates molecules from crude oil, promoting their diffusion into the aqueous phase and ultimately enhancing oil recovery. The steam condensation experiments clearly demonstrate that the presence of aerogel and CO2 exerts a substantial influence on the condensation heat transfer of steam, resulting in a reduction in the condensation heat transfer rate between the steam and the cooling wall. Additionally, molecular dynamics simulations reveal that silica aerogel nanoparticles exhibit an affinity for adsorbing onto hydrophobic quartz surfaces, forming an insulating layer between steam and quartz, thereby facilitating CO2 sequestration. The introduction of silica aerogel nanoparticles expands the swept volume of steam heat. This study provides valuable insights into the underlying mechanisms responsible for improved CO2 sequestration and increased oil recovery through the implementation of silica aerogel nanoparticles, offering fresh perspectives on heavy oil recovery.

Steamflood Injection Performance on 2 Types of Sand Heterogeneity in XYZ Field

Steamflood is one of the best thermal enhanced oil recovery methods to improve heavy oil production. This project focuses on the benchmarks of steamflood performance in two types of sand: homogenous and heterogeneous formations in the XYZ field. The co-kriging technique was implemented to generate the porosity and net to gross distribution. Afterward, twelve designs of experiments were run to obtain the oil production information and analyze the affecting factors of steamflood performance on each sand. The findings showed that clean sand provided higher oil production compared to the fining sand. Additionally, the well spacing had a higher contribution compared to the steam quality in applying steamflood injection. This study could serve as a guideline for engineers for planning the well spacing and steam quality utilization in steamflood injection in these two types of sand formation that contain heavy oil reserves.

Optimization of Efficient Development Modes of Offshore Heavy Oil and Development Planning of Potential Reserves in China

Thermal recovery is still the most important means to increase heavy oil EOR. With the increase in the recovery factor and the difficulty of exploiting new exploration reserves, the efficient utilization of offshore heavy oil reserves has attracted much attention. However, due to the challenges of high development investments, high operating costs, platform safety factors, and high economic cumulative yield, the offshore heavy oil reserves of nearly 700 million tons have not been effectively utilized. In this paper, Chinese offshore heavy oil reserves were taken as the research object. The indoor one-dimensional experiments were carried out to optimize an applicable development method, and the superheated steam huff and puff was selected as the injection medium for high-speed and high-efficiency development of offshore heavy oil, which verified the great potential of the application of superheated steam in offshore heavy oil thermal recovery. A numerical simulation model for offshore heavy oil superheated steam injection development was established, and a dynamic model considering the thermal cracking of heavy oil was established through historical matching. Through the field numerical simulation models, the whole process development mode of a single sand body, thin interbedded reservoir superheated steam huff and puff turning to superheated steam flooding, and thick layer super heavy oil reservoir with bottom water sidetracking after superheated steam huff and puff for eight cycles was established. Through the numerical simulation method and grey correlation method, the main control factors of superheated steam development of different types of heavy oil reservoirs were determined, and the cumulative oil production charts of different types of reservoirs under the influence of the main control factors were built. The economic evaluation model of superheated steam development of offshore heavy oil was established. Combining multi-specialty of geological, reservoir engineering, drilling and completion, oceanographic engineering, economics, the economic limits of steam injection development under different reserve scales, and engineering conditions of offshore heavy oilfields were clarified. At last, we planned the economic production mode of undeveloped reserves and predicted the construction profile of superheated steam capacity of offshore heavy oil using the production charts and the economic charts. The research results clarify the great potential of thermal recovery development of offshore heavy oil, provide an important basis for the economic development of offshore heavy oil undeveloped reserves, and also provide an important decision for the sustainable and stable production of global heavy oil reservoirs.

Heavy oil recovery using gas injection methods and its challenges and opportunities

The relevance of enhanced oil recovery (EOR) and its development are always important considerations when it comes to the approaches used to improve heavy crude oil recovery. As a direct consequence of this, there is a growing demand for the discovery of unconventional resources such as bitumen, shale, and heavy oil. With the diminishing availability of conventional crude oil stocks, it is necessary to make efficient and fruitful use of heavy oil resources. Heavy oil recovery poses challenges due to the high viscosity and low mobility of the oil, making traditional recovery methods less effective. Gas injection has emerged as a promising technique to enhance heavy oil recovery, where different gas injection methods are evaluated to improve the oil displacement efficiency. Several gas injection methods have been employed in heavy oil recovery, including natural gas injection, carbon dioxide (CO2) injection, and steam-assisted gravity drainage (SAGD). Each method has its benefits and difficulties. Natural gas injection is relatively simple and cost-effective, but it may face limitations in terms of the amount of gas available and the gas-oil miscibility. CO2 injection has shown promising results due to its miscibility with heavy oil, which leads to improved oil recovery through swelling and viscosity reduction. The benefits of gas injection methods include increased oil recovery, reduced environmental impact, and potentially lower operational costs. These methods can also enhance the recovery of stranded heavy oil reserves, thereby contributing to global energy security. However, challenges associated with gas injection methods include high viscosity and low mobility, reservoir heterogeneity, the potential for gas channeling, and high capital and operational costs. Despite the challenges, gas injection methods offer significant opportunities for heavy oil recovery. Overcoming these challenges requires advanced reservoir characterization, optimized well design, efficient gas injection strategies. Technological advancements, such as advanced reservoir characterization techniques, improved well design, and optimized gas injection strategies, can help overcome these challenges and enhance heavy oil recovery using gas injection methods. The gas injection methods that are used to recover heavy crude oil have been evaluated in the research along with their benefits and the difficulties that can arise while employing the gas injection methods. This paper focuses on the challenges and opportunities of gas injection methods for heavy oil recovery.

In Situ Combustion of Heavy Oil within a Vuggy Carbonate Reservoir: Part I—Feasibility Study

Worldwide, the known recoverable heavy oil and bitumen reserves make up more than 64% of the total reserves, of which more than 60% are trapped in carbonates. Air injection has immense potential for hydrocarbon recovery from various reservoirs. While most of the successful air-based techniques are performed within carbonate reservoirs containing light oil, theoretically, in situ combustion (ISC) has also shown great potential for recovering heavy oil and bitumen. Carbonates are complex in terms of geology and are often associated with fractures and vugs that affect the fluid flow, pressure propagation and progression of the ISC reactions. This paper describes the first experiment in which the triple-porosity concept was applied to simulate heterogeneity through artificially induced vugs, core matrix and fractures. This approach was used to study the feasibility of the ISC recovery technique for heavy oil (14° API) within a dolomite reservoir using a combustion tube (CT) in an experiment performed at 1740 psig. The combustion front advanced through 78% of the core length prior to the termination of air injection, producing 80% of the initial oil. To differentiate between the various sources of the CO2 gas (a product of carbonate decomposition vs. the combustion reaction) the atomic ratios of (CO2 + CO)/CO = 6 and (CO2 + CO)/N2 = 0.21 were applied. Additionally, partial upgrading of the produced heavy oil was observed.

Synthesis of Hematite-Zeolite Nanocomposites and Its Application as Catalyst in Aquathermolysis Reaction in Intermediate Crude Oil

Non-conventional crude oil has 70% of total heavy crude oil reserves and potentially as an energy source. The enhancement of non-conventional crude oil production can be done by utilizing the Enhanced Oil Recovery (EOR) technique with aquathermolysis reaction. The nanocomposite of Activated Hematite-Zeolite has the best properties as a catalyst to provide aquathermolysis on crude oil. These materials were successfully synthesized by using the microwave-assisted co-precipitation method. The XRD pattern represents mixing both hematite and zeolite in mordenite structure at 2θ equal 6.57o; 9.77o; 19.65o; 22.36o; 25.72o; 26.36o and at 30.1o; 35.6o; 40.9o, respectively. A reduction in a viscosity of crude oil occured after the aquathermolysis test was run by nanocomposites about 30.03% and simultaneously enhance the ratio of C-H saturated. Hence, it had improved crude oil quality with larger molecules in crude oil divided into small molecules due to breaking C-C bonds.

Feasibility and Mechanism of Deep Heavy Oil Recovery by CO2-Energized Fracturing Following N2 Stimulation

There are large, heavy oil reserves in Block X of the Xinjiang oilfields, China. Due to its large burial depth (1300 m) and low permeability (26.0 mD), the traditional steam-injection technology cannot be used to obtain effective development benefits. This paper conducts experimental and simulation research on the feasibility and mechanism of CO2-energized fracturing of horizontal wells and N2 foam huff-n-puff in deep heavy oil reservoirs with low permeability in order to further explore the appropriate production technology. The foaming volume of the foaming agent at different concentrations and the oil displacement effect of N2 foam at different gas/liquid ratios were compared by the experiments. The results show that a high concentration of foaming agent mixed with crude oil is more conducive to increasing the foaming volume and extending the half-life, and the best foaming agent concentration is 3.0∼4.0%. The 2D micro-scale visualization experiment results show that N2 foam has a good selective blocking effect, which increases the sweep area. The number of bubbles per unit area increases as the gas/liquid ratio increases, with 3.0∼5.0 being the optimal gas/liquid ratio. Numerical simulation results show that, when CO2-energized fracturing technology takes into account the advantages of fracturing and crude oil viscosity reduction by CO2 dissolution, the phased oil recovery factor in the primary production period can reach approximately 13.7%. A solvent pre-slug with N2 foam huff-n-puff technology is applied to improve oil recovery factor following primary production for 5∼6 years, and the final oil recovery factor can reach approximately 35.0%. The methodology formulated in this study is particularly significant for the effective development of this oil reservoir with deeply buried depth and low permeability, and would also guide the recovery of similar oil deposits.

Numerical Modeling of Toe-to-Heel Air Injection and Its Catalytic Variant (CAPRI) under Varying Steam Conditions.

There are huge reserves of heavy oil (HO) throughout the world that can be energy-intensive to recover. Improving the energy efficiency of the recovery process and developing novel methods of cleaner recovery will be essential for the transition from traditional fossil fuel usage to net-zero. In situ combustion (ISC) is a less used technique, with toe-to-heel air injection (THAI) and catalytic processing in situ (CAPRI) being specialized novel versions of traditional ISC. They utilize a horizontal producing well and in the case of CAPRI, a catalyst. This paper aims to investigate the impact that injected steam has on both the THAI and CAPRI processes for the purpose of in situ HO upgrading and will help to bridge the gap between the extant laboratory research and the unknown commercial potential. This study also presents a novel method for modeling the THAI-CAPRI method using CMG STARS, proposing an in situ hydrogen production reaction scheme. THAI and CAPRI experimental-scale models were run under three conditions: dry, pre-steam, and constant steam. Starting from a reservoir American Petroleum Institute (API) of 10.5°, THAI reached an average API of ∼16 points, showing no increase in the API output with the use of steam injection. A decreased API output by ∼0.7 points during constant steam injection was achieved due to a high-temperature oxidation-dominant environment. This decreases the reactant availability for thermal cracking. The CAPRI dry run reached an API of 20.40 points and achieved an increased API output for both pre-steaming (∼21.17 points) and constant steaming (∼22.13 points). The mechanics for this increased upgrading were discussed, and catalytic upgrading, as opposed to thermal cracking, was shown to be the reason for the increased upgrading. Both processes produce similar cumulative oil (∼3150 cm3) during dry and pre-steamed runs, only increasing to ∼3300 cm3 with the constant steam injection during THAI and 3500 cm3 for CAPRI.

Influence and Mechanism Study of Ultrasonic Electric Power Input on Heavy Oil Viscosity

The reserves of heavy oil are enormous. However, its high viscosity and other characteristics make heavy oil extraction and transportation extremely difficult. Power ultrasonic (US) reforming technology on heavy oil has the advantages of environmental protection and fast results, so it is important to understand the mechanism of ultrasonic reforming. We examine the influence law of the electric power input of the US transducer on the viscosity of heavy oil. Fourier Transform Infrared Spectrometer (FTIR) and Gas Chromatography (GC) are applied to explain the changes in different functional groups, heavy components, and carbon chains before and after US irradiation. The cavitation noise method is also used to study the influences of variance in the intensity of cavitation on the viscosity of heavy oil. The results indicate that the viscosity of heavy oil first decreases, and next increases with an increase in electric power. The functional groups and chromatographic distillation also change in different forms, and with an increase in electric power, the cavitation effect is gradually enhanced. These findings suggest that it is not that the stronger the cavitation, the greater the influence on the viscosity of heavy oil.

Iron oxide nanoparticles impact on improving reservoir rock minerals catalytic effect on heavy oil aquathermolysis

The past decade has seen a renewed importance in developing heavy oil reserves due to the rapid raise in energy resources’ demand. The next decade is likely to witness a considerable rise in extracting these resources by thermally enhanced oil recovery methods. However, many hypotheses regarding the influence of reservoir mineral components on aquathermolysis reactions appear to be disputable. This paper outlines a new approach to model the aquathermolysis of Aschalcha’s reservoir rock heavy oil in the presence and absence of iron oxide nanoparticles combined with hydrogen donor in water steam atmosphere at 200, 250, and 300 °C using different physical and chemical methods. X-ray powder diffraction (XRD) and scanning electron microscopy (SEM) have showed adsorbed spherical magnetite (Fe3O4) nanoparticles with less than 100 nm size on the studied rock minerals in hydrothermal conditions. Moreover, SARA (Saturates, Aromatics, Resins and Asphaltenes) analysis, gas analysis, and gas chromatography–mass spectrometry (GC–MS) have revealed that the obtained iron oxide nanoparticles exhibit their highest catalytic activity at 250 °C comparing to 200 and 300 °C respectively. What’s more, the obtained data have indicated a considerable decrease in resins (from 19.6 to 8.9 wt%) and asphaltenes compounds (from 5.1 to 1.5 wt%) in the presence of iron oxide nanoparticles comparing to the non-catalytic aquathermolysis of reservoir rock heavy oil. Contrary to resins and asphaltenes’ content, it has been found that saturates’ content increases significantly from 41.1% to 61.7% wt%. On another hand, the viscosity of the extracted oil has decreased almost 30 times and the gas proportion has doubled more than twice from 0.2 g to 0.43 g per 100 g of the reservoir rock sample. Interestingly, these results have been obtained in the presence of iron oxide nanoparticles at 250 °C, meanwhile, the same results have been found for the non-catalytic experiments at 300 °C. These findings confirm the significant contribution (synergistic effect) of iron oxide nanoparticles to stimulate the catalytic activity of the reservoir rock minerals. What’s more, the evidence from this study suggests that the presence of iron oxide nanoparticles in hydrothermal conditions at higher temperatures leads to the formation and adsorption of heavy coke-like carbenes, carboides, needle coke as well as carbon nanotubes of 100 nm size on the surface of the reservoir rock heavy oil as confirmed by thermal analysis (TG-DSC), SEM, and drop shape analysis (DSA) data.

Integration of Profile Control and Thermal Recovery to Enhance Heavy Oil Recovery

The proven reserves of heavy oil in the Bohai oilfield exceed 600 million tons. Heavy oil is highly viscous, temperature sensitive, and suitable for thermal extraction, but due to the strong inhomogeneity of the reservoir, the recovery rate of pure thermal extraction development is low, and there is an urgent need to conduct research on profile control + thermal extraction to guide the actual production. In this paper, we propose an integrated technology of profile control and thermal recovery to enhance heavy oil recovery. The heavy oil exhibited strong temperature dependence and nonlinear flow characteristics. An inorganic gel was selected for profile control to assist thermal recovery. Thermal recovery experiments were conducted in the laboratory using cores saturated by crude oil with different viscosities to simulate the oil in areas swept by thermal fluid. The 4% to 6% inorganic gel can seal up to 99% on 2000 × 10−3 μm2 cores. As the thermal recovery temperature increased from 55 to 200 °C, the efficiency of oil recovery increased from 10.8% to 42.9% in experiments with three-layer heterogeneous cores; it increased by 8.9–13.2% when profile control was implemented using the inorganic gel with a concentration of 4%. The injection parameters for thermal recovery were optimized with a thermal fluid swept area of 3/10 times the injector–producer distance, including three slugs of crude oil with different viscosities. According to the experiments involving an inverted nine-point well pattern, the integrated technology of profile control and thermal recovery enhances oil recovery by 1.4% compared to of profile control or thermal recovery alone.

A heavy oil reserve analysis for Trinidad and Tobago

A heavy oil reserve analysis for Trinidad and Tobago

Biosurfactant production and oil degradation by Bacillus siamensis and its potential applications in enhanced heavy oil recovery

The use of functional microbial strains is an emerging strategy for exploiting heavy oil reserves. The aim of this study was to obtain bacterial strains potentially applicable in enhanced heavy oil recovery. A biosurfactant-producing and oil-degrading strain, designated HoB-1, was isolated from a heavy oil sample collected at the Yanchang oilfield (Northwest China). Strain HoB-1 was identified as Bacillus siamensis on the basis of 16S rRNA gene sequence analysis. It showed the potential to produce biosurfactant, which lowered the surface tension of a 7-d-old fermentation broth by 38.6% compared with that of the control. In the presence of the biosurfactant, stable emulsions were formed with different hydrocarbons such as n-hexane, petroleum ether, and light oil. The biosurfactant exhibited high stability, even under extreme temperature (20–100 °C), pH (3.0–13.0), and salinity (0%–30% NaCl) conditions. Bacterial treatment with strain HoB-1 led to the transformation and redistribution of all four heavy oil fractions by reducing the saturates and asphaltenes contents and increasing the aromatics and resins contents. The individual contents of n-alkanes were also increased in the heavy oil upon bacterial treatment. Therefore, B. siamensis HoB-1 is a potential candidate for enhanced heavy oil recovery through biosurfactant production and oil biodegradation.