Recovery Of Heavy Oil Reservoirs Research Articles

Construction and Mechanism of Janus Nano-Graphite Reinforced Foam Gel System for Plugging Steam in Heavy Oil Reservoirs

High-temperature steam injection is a primary method for viscosity reduction and recovery in heavy oil reservoirs. However, due to the high mobility of steam, channeling often occurs within the reservoir, leading to reduced thermal efficiency and challenges in enhancing oil production. Foam fluids, with their dual advantages of selective plugging and efficient oil displacement, are widely used in steam-injection heavy oil recovery. Nonetheless, conventional foams tend to destabilize under high-temperature conditions, resulting in poor stability and suboptimal plugging performance, which hampers the efficient development of heavy oil resources. To address these technical challenges, this study introduces a foam system reinforced with Janus nano-graphite, a high-temperature stabilizer characterized by its small particle size and thermal resistance. The foaming agents used in the system are sodium α-olefin sulfonate (AOS), an anionic surfactant, and octadecyl hydroxylpropyl sulfobetaine (OHSB), a zwitterionic surfactant. Under conditions of 250 °C and 5 MPa, the foam system achieved a half-life of 47.8 min, 3.4 times longer than conventional foams. Janus nano-graphite forms a multidimensional network structure in the liquid phase, increasing internal friction and enhancing shear viscosity by 1.2 to 1.8 times that of conventional foams. Furthermore, the foam gel system demonstrated effective steam-channeling control in heterogeneous heavy oil reservoirs, particularly in reservoirs with permeability differentials ranging from 3 to 9. These findings suggest that the Janus nano-graphite reinforced foam system holds significant potential for steam-channeling mitigation in heavy oil reservoirs.

A New Model for Steam Cavity Expansion in Vertical Wells of Heavy Oil Reservoirs

Summary Steamflooding is one of the most effective and mature methods for developing heavy oil. However, existing research has not fully explained the phenomena of steam overburden and heat loss, particularly overlooking the steam velocity loss at the steam cavity front. Therefore, the condensation heat transfer coefficient (CHTC) was introduced to describe the decrease in steam velocity at the steam cavity front. A steam cavity front expansion model, considering shape factor, pseudofluidity ratio, and CHTC ratio (CHTCR), was established and validated by using mine monitoring data. The research results show that the steam cavity of the revised model is in the shape of a “funnel,” and the steam overburden phenomenon is more pronounced at the steam cavity front. Through comparison with the field data of the P6 and P612-1 well groups, it is observed that the average displacement error of the steam cavity front of the two is only 6.58%. As steam injection progresses, the steam cavity is more degraded, and the steam overburden phenomenon is more intensified compared with the initial stage. Taking into account the phenomenon of kinetic energy loss, a higher formation heat loss rate is calculated during the middle and late stages of steam injection in the modified model. The pressure gradient at the steam cavity front is analyzed to determine an optimal displacement radius of 40 m for vertical well steamflooding in heavy oil reservoirs. When parameters such as shape factor, steam injection rate, and CHTC are increased, the development shape of the steam cavity is more ideal, but the convexity of the steam cavity front is increasingly pronounced as the pseudomobility ratio increases. The CHTC was incorporated into the steam cavity expansion model, elucidating the steam overburden phenomenon and advancing the theoretical understanding of steamflooding. By improving the existing model, the analytical formula can be used to rapidly predict the position of the steam cavity front and estimate of the steam-saturated zone, even in the absence of some field data or numerical models. Practical guidance for optimizing steam injection strategies is provided, with the potential to significantly enhance the recovery of heavy oil reservoirs.

Thermal recovery of heavy oil reservoirs: Modeling of flow and heat transfer characteristics of superheated steam in full-length concentric dual-tubing wells

Accurately predicting the flow and heat transfer characteristics of superheated steam (SHS) in the wellbore is essential for efficiently developing heavy oil reservoirs. However, few studies have examined SHS flow in full-length concentric dual-tubing wells (CDTWs). In this paper, firstly, based on fluid dynamics and thermodynamics theories, a mathematical model for SHS flow in vertical and horizontal wellbores is proposed. Then, this model is solved using a finite difference method for spatial discretization and an iterative technique. Finally, model verification, type curve analysis, and sensitivity analysis are conducted sequentially. The results indicate that SHS temperature and pressure are independent variables, and the effect of friction energy on temperature is greater than its impact on pressure. The injection rate has a critical value, and the critical injection rates of the main controlling factors affecting the pressure drop and temperature drop of SHS in the vertical tubing are different. When the injection rate is below the critical value, the gravitational force of the SHS helps maintain high enthalpy. The SHS should be transported to the well bottom as quickly as possible. To enhance the uniform heating effect of the reservoir and improve heat utilization efficiency, a relatively small injection rate, high injection pressure, and low injection temperature are recommended. The uniformity of SHS pressure and temperature distribution in the horizontal annulus positively correlates with the uniformity of the reservoir's heat absorption rate. Achieving more uniform SHS pressure and temperature profiles in the horizontal annulus benefits the uniform heating of the reservoir.

Optimization of injection parameters of a microemulsion-type oil displacement agent for heavy oil recovery

The conventional viscosity reduction technology through commercial oil-soluble agents for enhanced oil recovery in heavy oil reservoirs has potential safety hazards. In this work, micro-emulsification of heavy oil is proposed as a means of reducing its viscosity for ease of its recovery. The microemulsion-type oil displacement agent was developed, and its performance was characterized by its pseudoternary phase diagram and dynamic light scattering tests. The core tests were used to study the effects of injection volume, injection speed, and subsequent water flooding speed on the oil recovery factors. These results were used to determine the optimal injection parameters. Furthermore, the displacement mechanism for heavy oil was determined based on combined macroscopic and microscopic visual tests. The results showed that the optimal injection volume is 0.15 PV (pore volume), the injection rate is 0.10 ml/min, and the subsequent water flooding rate is 0.20 ml/min. Based on the optimal parameters, the oil recovery efficiency can reach up to 39.83%, which is 25.69% higher than water flooding process. The displacement mechanism of the microemulsion can be divided into three stages. First, when the microemulsion is in contact with the heavy oil, the solubilization occurs spontaneously, and the heavy oil is peeled off from the rock surface. Then, the solvent in the microemulsion interacts with the heavy oil to achieve the viscosity decrease in the heavy oil. Third, during the water flooding process, the viscosity-reduced heavy oil can be emulsified to form oil-in-water emulsion, further realizing the viscosity reduction of heavy oil.

The macro and micro analysis on EOR mechanisms during steam and solvent thermal recovery in heavy oil reservoirs

Using only pure steam as a driving medium in heavy oil reservoirs may result in a low oil recovery factor. Solvent is a good oil displacement medium that can be dissolved in heavy oil, which can greatly reduce the viscosity and improve the mobility of heavy oil. Therefore, the method of solvent assisted displacement and drainage has the unique advantage during steam flooding. In this paper, a quantitative method is proposed to choose appropriate solvents. Then a series of experiments are carried out, including oil displacement experiment to measure oil displacement efficiency, 2D visualization experiment to analyze the sweep efficiency and remaining oil distribution, and 3D scaling physical simulation setting with bottom water condition, which are used to analyze production performance, the expanding characteristics of steam chamber and study reservoir fluid distribution. The results show that steam moving upwards to heat and drive heavy oil to production well under the action of displacement and drainage. In a heavy oil reservoir with thin bottom water, if only steam is injected into reservoir, then there is no obvious stage of stable oil production and the oil recovery factor is only 32.7%. However, when solvent and steam are co-injected into reservoir, the stage of stable oil production maintaining about 0.6 PV and the oil recovery factor is 43.2%. During steam and solvent flooding, solvent can greatly reduce the oil viscosity to improve its mobility; meanwhile solvent can promote the expansion of steam chamber. The co-injection of steam and solvent can obviously expand steam chamber and increase oil recovery factor in heavy oil reservoirs (even connecting with bottom water layer). The method of steam and solvent flooding further enriches EOR technologies of thermal recovery in heavy oil reservoirs.

Core scale analysis of low viscosity oil injection in enhancing oil recovery of heavy oil reservoirs

Core scale analysis of low viscosity oil injection in enhancing oil recovery of heavy oil reservoirs

Experimental Study on Water-Rock Interaction Characteristics of Unconsolidated Sandstone during CO2 Multicomponent Thermal Fluid Injection

According to the reservoir characteristics and the current situation of CO2 utilization during thermal recovery in an unconsolidated sandstone heavy oil reservoir, the mechanism and law of porosity and permeability change in an unconsolidated sandstone heavy oil reservoir during CO2+steam and CO2+steam+ sodium alpha-olefin sulfonate (AOS) injection were studied by combining a static monomineral water-rock reaction and a dynamic polymineral sand pack displacement experiment. In the static water-rock reaction between CO2 and monomineral of reservoir rock, the dissolution degree of monomineral at 200°C is greater than that at 100°C and 300°C, and the order of mineral dissolution is illite, montmorillonite, kaolinite, and quartz. Besides, the dissolution rate of single rock minerals decreased significantly in the system of CO2 with AOS. In the polymineral sand pack displacement experiment, the porosity gradually decreases by CO2 multicomponent thermal fluid, and the permeability first decreases and then increases by CO2 multicomponent thermal fluid, but the permeability change is only about 0.5% by CO2+steam+ AOS, which is mainly attributed to the adsorption of AOS on the rock surface, and it is confirmed in the infrared spectrum of unconsolidated sand after displacement. This also shows that CO2+steam+AOS can stabilize the rock skeleton structure of the reservoir and prevent the deterioration of heterogeneity in the subsequent development of thermal recovery of heavy oil reservoirs; therefore, the CO2 multicomponent thermal fluid with chemical agents can improve the damage of a single CO2 thermal fluid to the reservoir.

A Three-Phase Relative Permeability Model for Heavy Oil Emulsion System

Chemical flooding is important and effective enhanced oil recovery processes are applied to improve the recovery of heavy oil reservoirs. Emulsification occurs during chemical flooding processes, forming an oil-in-water (O/W) emulsion system. In this work, the heavy oil emulsion system is characterized as a three-phase (continuous oil phase, dispersed oil phase, and continuous water phase) system. Based on a capillary tube model, a new relative permeability model is proposed to describe the flow of the emulsion system in porous media quantitatively, considering the physicochemical properties of emulsions and the properties of porous media. A resistance factor is derived in this model to describe the additional resistance to the emulsion flow caused by the interaction between dispersed oil droplets and the pore system. Three dimensionless numbers related to the emulsion porous flow process were proposed and their different effects on the three-phase relative permeability are investigated. To validate the reliability of the proposed model, a one-dimensional O/W emulsion–oil displacement experiment is simulated. The maximum absolute error between the simulated results and experimental data is no more than 10%, and the new model can be used to describe the flow behavior of heavy oil emulsions in porous media.

Numerical simulation of steam flooding in offshore heavy oil reservoir after water flooding

Steam flooding is an effective method to enhance oil recovery in heavy oil reservoirs. However, the influence factors of steam flooding will affect the development of heavy oil reservoir after the traditional water flooding. So the dynamic prediction of steam flooding needs to be performed before the development scheme is implemented. In this study, the 3D reservoir model was established by the reservoir numerical simulation software CMG; Combined with operating parameters of oilfield, the influence of steam temperature, steam injection timing and steam quality on the development effect of L7 block in offshore heavy oil reservoir was studied by using 3D reservoir model. The results show that compared with traditional water flooding, steam flooding has better development effect, and the cumulative oil production can reach 100.673 × 104m3; With the increase of steam temperature and steam quality, the cumulative oil production, incremental oil production and heat efficiency have an increasing trend; This result also suggests that the development method of higher steam temperature and steam quality conforms to the principle of economic development; For steam injection timing, the earlier the steam injection is more conducive to better development results.

Change Characteristics of Heavy Oil Composition and Rock Properties after Steam Flooding in Heavy Oil Reservoirs

The thermal recovery method of steam flooding is one of the most common development methods for heavy oil reservoirs. However, after multiple rounds of steam injection development, the composition of crude oil and reservoir rock properties have changed greatly, which is unfavorable for the subsequent enhanced oil recovery. It is necessary to study the distribution of the remaining oil after the thermal recovery of heavy oil reservoirs, and clarify the change characteristics of the components of the crude oil under different steam injection conditions. At the same time, the change of porosity and the permeability of the rocks after steam flooding, and its influence on oil recovery, are investigated. In this paper, the composition changes of heavy oil before and after steam flooding are studied through experiments and numerical simulation methods. A numerical model is established to study the retention characteristics of heavy components in heavy oil reservoirs by the CMG software. The effects of different steam injection conditions, and heavy oil with different components on the residual retention of heavy components, are compared and studied. The changes of rock physical properties in heavy oil reservoirs after steam flooding is clarified. The results show that after steam flooding, the heavy components (resin and asphaltenes) of the recovered oil decrease, and the heavy components in the formation increase in varying degrees. With the increase of heavy components in the crude oil, the remaining oil in the formation increases after steam flooding, and the retention of heavy components increases; after steam flooding, the stronger the rock cementation strength, the higher the degree of reserve recovery, and it is difficult to form breakthrough channels; the greater the steam injection intensity, the earlier to see steam breakthrough in the production well, and the lower the degree of reserve recovery. The research reveals the changes of heavy oil components and rock properties after steam flooding, providing support for the subsequent enhanced oil recovery.

A new developed thermal model to predict formation failure in vertical wells during steam injection

As production from mature fields declines, finding technologies to improve hydrocarbon recovery is becoming extremely important in oil and gas industry. In this regard, steam injection through injection wells has proven to be an effective method for increasing oil recovery in heavy oil reservoirs. The implementation of this approach, however, raised the issue of wellbore instability due to the introduction of thermal stresses in the formations around the injection wells. In this work, a new stability model that covers the effect of thermal stresses and considers three-dimensional rock failure mechanism has been established for vertical wells. The developed model has been verified in two field cases. The model results have shown a good match with the actual field observations. The results of the study show that applying steam injection will lead to a significant dropping in the stability of the formations that can be predict by the developed geomechanical model. [Received: November 18, 2021; Accepted: May 18, 2022]

Research and Application Progress of Wet-Phase Modified Expandable Graphite as a Steam Plugging Agent in Heavy Oil Reservoirs

Wet-phase modified expandable graphite (WMEG) particles have been successfully developed for in-depth steam channeling control in heavy oil reservoirs. WMEG particles can expand 4 to 7 times in a wet-phase environment and form a worm-like structure at steam temperature. The sand-pack flowing experiments demonstrated that WMEG particles have good injection, steam erosion resistance, and selective plugging capacity characteristics. By directly plugging and bridge plugging after expansion, WMEG particles can effectively plug steam channels. This paper also analyzes the EOR potential of WMEG particles through oil displacement experiments, proving that WMEG particles can further enhance oil recovery of heavy oil reservoirs. To better explain the steam plugging mechanism, the energy changes during WMEG particle expansion were also analyzed. The release of gas at different stages is the source of energy for WMEG particle expansion. WMEG particles have been successfully applied to 12 wells of four typical heavy oilfields in China. The results from these applications confirm that the injection of WMEG particles is an effective steam channeling control treatment. The success of these oilfield tests can also serve as a reference for similar steam injection heavy oilfields.

Experimental Measurements and Numerical Simulation of H2S Generation during Cyclic Steam Stimulation Process of Offshore Heavy Oil from Bohai Bay, China

Cyclic steam stimulation (CSS) is successfully applied to increase heavy oil recovery in heavy oil reservoirs in Bohai Bay, China. However, during the CSS processes, hydrogen sulfide (H2S) was detected in some heavy oil reservoirs. The existing literature mainly focused on the H2S generation of onshore heavy oil. There is no concrete experimental data available, especially about the level of H2S generation during CSS of offshore heavy oil. In addition, there is still a lack of effective reaction kinetic models and numerical simulation methods to simulate H2S generation during the CSS of offshore heavy oil. Therefore, this paper presents a case study from Bohai Bay, China. First, the laboratory aquathermolysis tests were conducted to simulate the gases that are produced during the CSS processes of heavy oil. The effects of the reaction temperature and time on the H2S generation were studied. Then, a one-dimensional CSS experiment was performed to predict H2S generation under reservoir conditions. A kinetic model for the prediction of H2S generation during the CSS of heavy oil was presented. The developed model was calibrated with the experimental data of the one-dimensional CSS experiment at a temperature of 300 °C. Finally, a reservoir model was developed to predict H2S generation and investigate the effects of soaking time, steam quality, and steam injection volume on H2S generation during CSS processes. The results show that the H2S concentration increased from 0.77 ppm in the first cycle to 1.94 ppm in the eighth cycle during the one-dimensional CSS experiment. The average absolute error between the measured and simulated H2S production was 12.46%, indicating that the developed model can accurately predict H2S production. The H2S production increase with soaking time, steam quality, and steam injection volume due to the strengthened aquathermolysis reaction. Based on the reservoir simulation, the H2S production was predicted in the range of 228 m3 to 2895 m3 within the parameters of this study.

Multi-Component Thermal Fluid Injection Performance in Recovery of Heavy Oil Reservoirs

Field observations discern that the oil production rate decreases substantially and water cut increases rapidly with the increase of steam injection cycles. Compared with steam drive, the advantage of flue gas (also called multi-component thermal gas) co-injection with steam is that flue gas can increase the reservoir pressure and expand the heating chamber. In this paper, the flue gas generated by fuel burning in the field was injected with steam to improve heavy oil recovery. This technique was investigated in the large laboratory 3D model and implemented in the field as well. The huff-n-puff process efficiency by flue gas, steam, and flue gas–steam co-injection was compared in the experiments. The field practice also demonstrated that the addition of non-condensable gas in the steam huff-n-puff process recovered more oil than steam alone. The temperature profile in the wellbore with flue gas injection is higher than that with steam injection since the low thermal conductivity of N2 reduces the heat loss. With the increase of stimulation cycles, the incremental oil recovery by flue gas injection declines significantly.

A novel method for improving recovery of heavy oil reservoirs with high water cut based on polymer gel-assisted CO2 huff and puff

A novel enhanced oil recovery (EOR) method based on polymer gel-assisted carbon dioxide (CO2) huff and puff was developed aiming to improve the development effect of heavy oil reservoirs with high water cut. The polymer gel prepared using partially hydrolyzed polyacrylamide (HPAM), hexamethylenetetramine, phenol, resorcinol, oxalic acid, and thiocarbamide as raw materials had a special network structure to overcome the challenge of significant heterogeneity in heavy oil reservoirs. The strength of polymer gel reached the maximum value 20,000 mPa·s within 22 h. The temperature resistance and salt resistance of polymer gel directly determined the plugging effect. The polymer gel was placed for 190 days at 85 ℃, and its apparent viscosity retention rate was 66.4%. The salt resistance experiments showed that the apparent viscosity retention rate of this polymer gel at 1.8 wt % NaCl, 0.045 wt % CaCl2, 0.045 wt % MgCl2 was 71.3%, 78.5%, 71.4%, respectively. Huff and puff experiments confirmed that this method could be used to increase the sweep volume and improve the oil displacement efficiency of heavy oil reservoirs with high water cut. Furthermore, the EOR of this method was better than that of water huff and puff, polymer gel huff and puff or CO2 huff and puff.

Evaluation of the MEOR technique as an alternative for enhanced recovery in heavy oil reservoirs.

Evaluation of the MEOR technique as an alternative for enhanced recovery in heavy oil reservoirs.

Research on Mechanism of Enhancing Recovery of Heavy Oil With N2 Huff-n-Puff Assisted by Viscosity Reducer

In this paper, viscosity reducer of viscosity-reducing ability and foaming ability on the recovery efficiency in N2 huff-n-puff were studied. The optimal 4# viscosity reducer was selected by evaluating the ability of viscosity-reducing, emulsion stability, interfacial performance and foaming. The huff-n-puff experiments of single sandpack and dual sandpack were carried out under the reservoir conditions. The results showed that, the viscosity reduction rate of 4# viscosity reducer was more than 90% at 50 ~ 90℃, and it could form a stable oil/water emulsion when applied to heavy oil. Under the action of 4# viscosity reducer, the interfacial tension between oil and water decreased to 0.41 IFT/mN·m-1 and 0.19 IFT/mN·m-1 at 50℃ and 80℃, respectively. In the single sandpack huff-n-puff experiment, the 4# viscosity reducer could inhibit N2 bubbles coalesced in large channels and improve the mobility of heavy oil. Compared with N2 huff-n-puff, the recovery rate of N2 huff-n-puff assisted by 4# increased by 8.53%. In the dual sandpack huff-n-puff experiment, the N2 was inhibited to flow from the low permeability sandpack to the high permeability sandpack by 4# viscosity reducer, and the gas production of the low permeability sandpack increased by 284.71%. Under the combined action of viscosification and plugging, the total oil production of the sandpack increased by 7.88%. Therefore, N2 huff-n-puff assisted by viscosity reducer has a significant effect on enhancing oil recovery in heavy oil reservoirs.

Investigation of the Heat Transfer Mechanism of CO2-Assisted Steam Injection via Experimental and Simulation Evaluation

Steam injection is an important process for the thermal recovery of heavy oil reservoirs. As a non-condensable gas (NCG), CO2-assisted steam injection can not only improve the development effect but also reduce carbon emissions. In this study, the simulation method was combined with the experimental method. Based on an experiment using steam condensation with or without CO2, the influence of the condensation mode on steam heat transfer was considered. The effect of changes in the steam flow rate on phase transition and steam quality were analysed. The heat transfer effects of the gas-steam mixture with different contents of CO2 were compared. The results show that the surface condensation mode changes from dropwise condensation to film condensation with the addition of CO2, and the average temperature of the condensation block decreases by 20.05%. With increases in the steam flow rate, the quality of steam increases, and the heat transfer coefficient of steam on the condensation surface increases. With increase in CO2 content, the temperature of the gas-steam mixture decreases, and the inhibition effect on steam heat transfer is more obvious.

Experimental investigation on improving steam sweep efficiency by novel particles in heavy oil reservoirs

Steam channeling, an inevitable and severe problem in the steam injection process, seriously affects the oil production and ultimate recovery of heavy oil reservoirs. In this paper, a novel low-temperature thermo-expandable graphite (TEG) particle, prepared by the chemical oxidation method, was firstly used to solve the universal problem of steam channeling. The functional groups, microstructure, and morphology changes of TEG particles were characterized during intercalation and expansion process. A series of experiments were performed to study the expansion capacity, suspension system, plugging and injection performance of TEG particles. Based on this, oil displacement experiments were conducted to study the effect and mechanisms of the multi-stage plugging technique using the optimized particle system. The results showed that TEG particles had an initial expansion temperature of 140 °C. The expansion volume can reach more than ten times under the condition of high-temperature steam, which was much smaller than that under dry conditions. The expansion volume increased with the increase of particle size and steam temperature. TEG particles with soft property can deform and migrate through pores and throats, and expand into a worm-like morphology under high-temperature steam, directly blocking the pores and throats. The plugging and injection performance of the TEG particle system under different influencing factors were evaluated. And the multi-stage plugging technique can effectively plug the high permeable channels where steam channeling occurs step by step to divert the subsequent steam into the unswept area, thus significantly improving the oil recovery. This article provides a novel plugging agent that is expected to be an excellent substitute for conventional plugging agents and an effective method to solve the problem of steam channeling in heavy oil reservoirs.

CFD simulation of propane combustion in a porous media: application to enhanced oil recovery of heavy oil reservoirs

In-situ combustion process is a widely used approach as an enhanced oil recovery (EOR) method in shale and heavy oil reservoirs. In this present contribution, normal propane combustion has been investigated in a porous media. In this regard, fluid flow and heat transfer equations coupled with reaction network of propane combustion in a porous media and solved with COMSOL software. A good agreement was observed between modeling results and experimental investigation of propane combustion (AARD equal to 6.99%). Although hydrodynamic of propane combustion in porous media and its effect on the concentration distribution of materials has been studied.