Development Of Heavy Oil Reservoirs Research Articles

Evaluation of Viscosity Reducers for Heavy Oil Reservoirs: Experimental Testing and Numerical Simulation.

The application of thermal recovery methods in Chad's heavy oil fields has proven to be challenging, necessitating the development of chemical cold production technologies. The mechanisms causing heavy oil viscosity remain unclear, and the effects of adding viscosity reducers in wells with varying water contents are not well understood. In this study, the composition and structure of Chad's heavy oil samples were experimentally analyzed, revealing that the viscosity is primarily due to the accumulation of isoprenoid-like components and the high concentration of side-chain naphthenes in the oil's saturated fraction. Based on this mechanism, viscosity reducers were screened, with DG, a high-molecular-weight water-soluble viscosity reducer, demonstrating the most effective results. Numerical simulation was then employed to characterize the mechanism of viscosity reducers and to model the impact of adjusting daily production rates and introducing viscosity reducers in wells with different water contents on the cumulative oil recovery. The field numerical model was used to simulate for 10 years, and the results showed that for high water content wells, the injection of viscosity reducer reduced the daily fluid volume by 10%, and the cumulative recovery rate increased by 6.75%; for low water content wells, the injection of viscosity reducer increased the daily fluid volume by 20%, and the cumulative recovery rate increased by 3.08%. This research aims to provide new insights into the development of heavy oil reservoirs.

Multiphysics Field Coupled to a Numerical Simulation Study on Heavy Oil Reservoir Development via Electromagnetic Heating in a SAGD-like Process

Conventional thermal recovery methods for heavy oil suffer from significant issues such as high water consumption, excessive greenhouse gas emissions, and substantial heat losses. In contrast, electromagnetic heating, as a waterless method for heavy oil recovery, offers numerous advantages, including high thermal energy utilization, reduced carbon emissions, and volumetric heating of the reservoir, making it a focus of recent research in heavy oil thermal recovery technologies. This paper presents a numerical simulation study of electromagnetic heating for heavy oil recovery, using a heavy oil block in the Bohai Bay oilfield in China as a case study. Firstly, a multiphysics field coupled to a mathematical model was established, considering the impact of the temperature on the heavy oil viscosity, the threshold pressure gradient of non-Darcy flow, and the dielectric properties of the reservoir, along with heat dissipation from overlying and undercover sandstone and gravitational effects on fluid flow. Secondly, a numerical simulation method for the coupled multiphysics fields was developed, and the convergence and stability of the numerical simulation method were tested. Finally, a sensitivity analysis based on the numerical simulation results identified the factors affecting heavy oil production. It was found that electromagnetic heating significantly enhances heavy oil production, and the threshold pressure gradient greatly influences the prediction of heavy oil production. Moreover, heat dissipation from the overlying and undercover sandstone severely reduces cumulative oil production. When the production well is located below the electromagnetic heating antenna, larger well spacing results in higher cumulative heavy oil production. Higher heavy oil production is achieved when the antenna is positioned at the center of the reservoir for the studied cases. Power has a big effect on increasing heavy oil production, but its influence diminishes as power increases. There exists an optimal range of electromagnetic frequencies for maximum cumulative production, and higher water saturation leads to poorer electromagnetic heating efficiency. This study provides a theoretical foundation and technical support for the numerical simulation technology and development plan optimization of heavy oil reservoirs subjected to electromagnetic heating.

CO2-Induced In-Situ Targeted Precipitation of Asphaltene in Heavy Oil Reservoirs: Balancing Formation Gas Channeling Regulation and Wellbore Asphaltene Blockage Prevention

Summary To investigate the mechanisms of the asphaltene precipitation in oil caused by CO2, the sandstone core oil displacement experiments and asphaltene structure observation experiments are designed in this work. The oil displacement experiments create CO2 flooding conditions under different pressures in heavy oil reservoirs and analyze the produced oil components and precipitated asphaltene proportions. Meanwhile, nuclear magnetic resonance (NMR) analysis is conducted on the sandstone cores to discuss the precipitation characteristics of asphaltene in the reservoir pores. The observation experiments analyze the microstructure of precipitated asphaltene after interactions between oil and CO2. The results show that the increasing pressure promotes the precipitation of asphaltene from oil by enhancing the dissolution and component extraction of CO2 in oil, which reduces oil viscosity and promotes reservoir development efficiency. This process also leads to an increase in CO2 sequestration in the reservoir. However, the precipitated asphaltene reduces reservoir permeability, hindering the optimization of the oil recovery rate. During the process of increasing pressure, the rate of increase in oil recovery decreases. In reservoirs containing oil with high asphaltene proportion, the oil recovery rate even decreases under high pressure. Additionally, in-situ targeted precipitation and retention of asphaltenes in large pores can reduce the distribution differences of pores with different sizes in the reservoir, weakening the above negative effects and enhancing oil recovery by regulating gas channeling. Moreover, the ratio of resin in oil affects the asphaltene precipitation form, and CO2 can promote the association of asphaltenes by weakening the steric stabilization effect of resin on asphaltene in oil, which makes the microstructure of precipitated asphaltenes dense and regular and promotes asphaltene precipitation and oil recovery increasing. This work aims to verify the advantages of CO2-induced asphaltene precipitation in improving the efficient and environmentally friendly development of heavy oil reservoirs, while exploring the significance of CO2 flooding in promoting carbon sequestration.

Research on the Phase Behavior of Multi-Component Thermal-Fluid-Heavy Oil Systems

Multi-component thermal luid technology optimizes development effects and has a strong adaptability, providing a new choice for the efficient development of heavy oil reservoirs. However, due to the significant differences between the phase behavior of multi-component thermal-fluid-heavy oil systems and conventional systems, and the lack of targeted and large-scale research, key issues such as the phase behavior of these systems are unclear. This research studies the phase behavior and influencing factors of emulsions and foamy oil in a multi-component thermal-fluid-heavy oil system through high-temperature and high-pressure PVT experiments, revealing the characteristics of the system’s special phase behavior. In the heavy oil emulsion system, the water content directly affects changes in the system’s phase state. The higher the temperature, the larger the phase transition point, and the two are positively correlated. As the stirring speed increases, the phase transition point first increases and then decreases. The amount of dissolved gas is negatively correlated with the size of the phase transition point, and dissolution can form foamy oil. In the heavy oil–foamy oil system, the dissolution capacity of CO2 is greater than that of multi-component gases, which is greater than that of N2. A high water content and high temperature are not conducive to the dissolution of multi-component gases. While an increase in stirring speed is beneficial for the dissolution of gases, there are limitations to its enhancement ability. Therefore, the development of multi-component thermal fluids should avoid the phase transition point of emulsions and promote the dissolution of multi-component gases.

Experimental study on in-situ emulsification of heavy oil in porous media

Under the strategic goal of “dual-carbon”, reducing oil viscosity by in-situ emulsification using chemical method has become a new direction for high-efficiency and low-carbon development of heavy oil reservoirs. This technology can transform the originally immovable heavy oil into movable dispersed oil droplets through in-situ emulsification, and thus enhances heavy oil recovery. However, there is still a lack of sufficient understanding about the characteristics and influencing laws of in-situ emulsification of heavy oil in porous media. So, this paper carried out experimental studies on in-situ emulsification and influencing factors for heavy oil in porous media. The results show that, due to the transport and adsorption loss of viscosity reducer in porous media, the emulsification area expands gradually from the inlet to the outlet. At the same sampling position, with the increase of injection volume, the dispersed oil droplet size decreases, the distribution density increases, and the color of produced liquid changes from light yellow to dark brown. Under the same injection volume, the closer to the outlet, the smaller the particle size of the dispersed oil droplets and the higher the distribution density, which is resulted from the shearing effect of the porous media. With the increase of injection rate, the hydrodynamic shear effect is enhanced, so the in-situ emulsification of heavy oil starts earlier and the emulsification oil ratio curves have a higher slope and distribute more densely. With the increase of agent concentration, the adsorbed number of viscosity reducer molecules on the oil–water interface is increased, making it easier to emulsify the remaining oil. With the increase of pre-conversion oil recovery, the remaining oil in the porous media is more dispersed and the oil–water contact surface increases, so the emulsification is easier and the percentage of dispersed oil droplets in the produced oil phase increases. The research results based on sampling analysis deepen our understanding on in-situ emulsification of heavy oil in porous media, which provides valuable reference for designing suitable viscosity reducer agent and effectively enhancing heavy oil recovery in the future.

Molecular insight into the enhanced oil recovery potential of a seawater-based zwitterionic/anionic surfactant compound for heavy oil reservoirs

Zwitterionic/anionic surfactant mixtures can produce many synergistic effects that benefit heavy oil production. In this work, a seawater-based zwitterionic/anionic surfactant compound was prepared using cocoamidopropyl betaine (CAB) and alkyl polyoxyethylene ether sodium sulfate (AES), emphasizing their synergistic effects in enhancing conventional heavy oil recovery. First, the emulsification capability and the oil displacement efficiency of the surfactant compound were tested through laboratory experiments. Then the impacts of salinity, cation types, surfactant formulation and solution pH on surfactant-surfactant or surfactant-heavy oil interactions were systematically explored through molecular dynamics simulations to unveil the underlying mechanisms of enhanced oil recovery. The results showed that, (1) in a seawater-based system, when the AES/CAB concentration ratio was 1:1, a large wormlike micelle was formed due to the cation bridging of Ca2+ and Mg2+ ions, which not only strengthened the attractive interactions between the AES-SO4− and the CAB-N+ functional groups, but also screened the repulsive interactions between the AES-SO4− and the CAB-COO− functional groups. (2) Through mixed adsorption, the arrangement of AES/CAB molecules at the aqueous/heavy oil interface was more compact. (3) By incorporating the AES/CAB mixture into the associative structures of asphaltene and resins, it could effectively weaken the attraction interactions between the asphaltenes and the resins. Through these synergies, an additional oil recovery of 24.93 % was yielded by combining AES/CAB flooding and subsequent seawater flooding, compared to 19.38 % in the pure AES case. This study provides important insights into the microscopic mechanisms of zwitterionic/anionic surfactant mixtures, which can facilitate the effective development of heavy oil reservoirs and guide the complex formulation of cost-effective surfactant compounds.

A Novel Quantitative Evaluation Method for Viscosity Reduction Effect of Heavy Oil Cold Recovery Based on The Area Diffusion Process

After thermal recovery, the emulsification viscosity reduction technology for heavy oil cold recovery exhibits low energy consumption and low cost, making it a promising technology for ongoing heavy oil reservoir development. The evaluation and optimization of viscosity reducer is very important for the cold recovery of heavy oil. Prior research mostly employed the high-speed shear technique to measure viscosity following emulsion formation in order to evaluate viscosity reducers. This method ignores the seepage emulsification process under low dynamic conditions of formation, resulting in the selected viscosity reducer ' qualified but not ideal '. Based on the regional diffusion process, a quantitative evaluation method for cold recovery of heavy oil viscosity reduction is put forward. This method is used to simulate the static emulsification effect of heavy oil under real formation conditions, and quantitative evaluation is carried out. The outcomes demonstrate that, in comparison to the conventional assessment approach, this method is more accurate in selecting a viscosity reducer. Appropriately increasing the concentration of the viscosity reducer can improve the efficiency of viscosity reduction. The viscosity reduction effect improves with reservoir temperature. Heavy oil and viscosity reduction agent may be quickly matched using the prediction model of viscosity reduction in cold recovery of heavy oil developed by orthogonal experiment. At the same time, through field practice, the viscosity reducer chosen by this way has a good oil increase impact on oilfield production.

Coupling Mechanism of Multiple-Thermal-Fluid Multi-Cycle Stimulation in Ultra-Heavy-Oil Reservoirs

Multiple-thermal-fluid (MTF) stimulation technology has been successfully applied in heavy-oil reservoir development, resulting in the significant enhancement of oil production. However, the underlying mechanism of multi-component coupling remains unclear. This paper constructs a coupling model for MTF stimulation, investigates the coupling mechanism of different media in various zones during multiple-cycle stimulation operations, and compares the implementation effect with field results. The findings reveal that (1) based on media distribution, the area from near-wellbore to far well locations can be divided into four zones: high-temperature oil-viscosity-reduction zones, compound action zones, energy-replenishment zones, and unaffected zones. (2) In the high-temperature oil-viscosity-reduction zone, the latent heat of vaporization is released by steam, and ultra-heavy oil absorbs heat and reduces its viscosity, which plays a dominant role in the production of MTF. In the compound action zone, hot water, CO2, and N2 exhibit a synergistic effect which enhances overall performance. In the energy-replenishment zone, a small amount of N2 provides pressure maintenance and an additional energy supply. (3) As more cycles of stimulation are conducted, the compound action zone expands, while the energy-replenishment zone contracts. Simultaneously, there is a decrease in contribution rate from the high-temperature viscosity-reduction zone to oil production but an increase from both the compound action zone and energy-replenishment zone up to 30%. Based on the dynamic law of representative wells, this paper proposes a multi-media zonal coupling mechanism, providing a reference for subsequent research on MTF stimulation mechanisms and the adjustment of production measures.

Study on the influence of parameters on chemical agent assisted cyclic steam injection

Cyclic steam injection is widely applied in the development of heavy oil reservoirs. However, as reservoir development continues, steam channeling phenomena become increasingly severe, Serious impact on development effectiveness. Slug combinations of gel and foam is more effective than using gel and foam alone for steam channeling control. In this study, taking a steam channeling well in the A oilfield as an example, a numerical simulation model is established using CMG software. Based on this model, the effects of foaming agent concentration, foaming agent injection rate, gel injection timing, and nitrogen injection quantity on the development performance in the gel foam slug steam channeling plugging system are investigated. The research results indicate that higher foaming agent concentration, faster injection rate, and earlier gel injection timing lead to increased oil production. The nitrogen injection quantity exhibits an optimal value. Comparing the performance of gel foam slug system assisted cyclic steam injection with steam huff and puff alone, the results show that the gel foam slug system assisted cyclic steam injection achieves an incremental oil production of 9104 m3 over four cycles, as compared to steam huff and puff alone.

Experimental investigation of in situ combustion (ISC) in heavy oil thermal recovery

With the intensification of global climate change, there is an urgent need to change the energy structure of oil and gas to reduce the impact on the environment. As a thermally enhanced oil recovery technique, in situ combustion (ISC) is very important for reducing carbon emissions in the petroleum industry through the comprehensive utilization of oil displacement and storage in reservoirs. In this paper, the similarity parameters of a three-dimensional (3D) physical simulation of ISC were determined, the temperature field changes in the combustion process were monitored in real time, and a 3D field map was obtained. The oxidation characteristics of heavy oil were examined via thermogravimetry (TG), and the results showed that the oxidation process of heavy oil had three stages. The experimental results indicated that ISC could greatly increase the reservoir temperature, improve the quality of crude oil through high-temperature cracking, reduce the viscosity of crude oil and enhance the oil fluidity. The recovery factor from the ISC reached 53.27%. The formation of the coking zone was caused by various chemical and physical changes that occurred at high temperatures. Moreover, the formation process led to a concentration of the remaining oil in the small-aperture channels in the coking zone; this reduced the fluidity and increased the production difficulty. This study could provide guidance for the development of heavy oil reservoirs.

Research and Practice of Heavy Oil Hydraulic Pump Lifting Technology in Bohai Bay K Oilfield

In the early stage of heavy oil reservoir development in Bohai Bay K Oilfield, crude oil viscosity is high, conventional lifting processes have poor adaptability, and production energy consumption is high; Entering the stage of ultra-high water cut development, the company implemented carbon dioxide huff and puff, the difficulties in lifting matching brought about by the integrated wellbore requirements of injection and production, high gas-liquid ratio lifting, and enhanced corrosivity of the produced fluid. It conducted research on concentric dual/single pipe hydraulic lifting technology for heavy oil reservoirs, and conducted field practice. The research results and field practice show that the hydraulic pump lifting technology has good adaptability for both heavy oil sand production wells and heavy oil carbon dioxide huff and puff wells, effectively reducing the energy consumption of heavy oil lifting, significantly extending the pump inspection cycle of heavy oil sand production wells, significantly improving the lifting adaptability of carbon dioxide huff and puff wells, and has high promotion value in similar reservoirs and single wells.

Modeling of multiple thermal fluid circulation in horizontal section of wellbores

The development of heavy oil reservoirs has broad prospects. Because heavy oil reservoirs have the characteristics of high viscosity and poor fluidity, they often need to be heated. For heavy oil reservoirs, the effect of simple steam injection development is limited. By mixing superheated steam or steam with non-condensable gas, the development effect of heavy oil can be improved. Due to the high viscosity of heavy oil reservoirs, the initial injection capacity of the heat carrier is poor, and cyclic preheating is often required. In this paper, through theoretical research, the process of multi-element thermal fluid injection in heavy oil reservoirs is studied. The circulation preheating characteristics of the multi-element thermal fluid inside the wellbore are analyzed. Results show that for different ratios of nitrogen to carbon dioxide: when the multi-element thermal fluid flows from the finger end (1000 m) to the heel end (0 m) of the annular space, the oil layer heat absorption rate first drops and then rises.

Research on molecular mechanism and prediction model of viscosity reduction of heavy oil by different types of gas

ABSTRACT Dissolved gas flooding techniques are widely used in the later stages of heavy oil reservoir development. The role of foam oil in enhancing oil recovery from heavy oil solution gas has been researched. However, it is difficult to analyze the molecular mechanism of foam oil in the dissolved gas property theory and viscosity prediction model proposed by other scholars. In this study, the microscopic mechanism of the interaction between gas molecules and heavy oil molecules in foaming oil was analyzed by the variation of bubble point pressure and viscosity of different dissolved gases (CO2, N2, CH4) in heavy oil samples. By comparing the variation of bubble point pressure of different dissolved gas samples, it was found that the interaction between gas molecules and heavy oil molecules seriously affected the solubility of gas in heavy oil at the same temperature and pressure. An increase in the solubility of the gas in the dissolved gas sample of heavy oil increases the bubble point pressure. The factors influencing the viscosity of heavy oil show that pressure has the least effect on the viscosity reduction of dissolved gas. The higher the concentration of dissolved gas, the more pronounced the viscosity reduction effect. However, the viscosity reduction performance of the dissolved gas in heavy oil became less effective as the temperature increased. Samples A, B, and C, at 15 mol% CO2 concentration, the dissolved gas viscosity reduction effect decreases by 13.75%, 9.7%, and 12.2% when the temperature is increased by 40°C. In addition, samples A, B, and C, at 50°C and 10 mol% gas solubility, the viscosity reduction effect of CO2 is 25.6%, 8.6%, and 19.7% lower than that of N2. Based on the influencing factors of viscosity reduction of heavy oil dissolved gas, this study modified the FJ viscosity prediction model and proposed a physically meaningful heavy oil viscosity prediction model. The model predicts the viscosity of heavy oil dissolved gas with over 90% accuracy (R2 > 0.9) and has some applicability to mixed component gases.

Experimental analysis of the stimulation mechanism of CO2-assisted steam flooding in ultra-heavy oil reservoirs and its significance in carbon sequestration

In this work, the mechanisms of CO2-assisted steam flooding in ultra-heavy oil reservoir development are discussed. One-dimensional models are established to simulate the reservoirs, and the development characteristics of CO2-assisted steam flooding are studied. The feasibility of this development method in carbon sequestration is verified by analyzing the produced oil components. Subsequently, two-dimensional models are used to create the visual reservoir profiles, observe the fluid distribution in the reservoir, and analyze the influence of CO2 on the steam heat transfer. The results show that the steam sweep efficiency of steam flooding is poor due to the unsatisfactory displacement mobility ratio, heat loss and channeling. The oil recovery is below 50%. However, during CO2-assisted steam flooding, the recovery factor is increased to about 60%. The injected CO2 is expanded by heat, pushing steam deeper into the reservoir. It dissolves in oil to form foam, which alleviates channeling while optimizing steam sweep efficiency. In addition, CO2 can indirectly separate heavy components from oil to reduce its viscosity and improve displacement mobility ratio. Meanwhile, it can reduce the thermal conductivity and the condensation heat transfer coefficient of the medium, reduce the steam heat loss, which allows more heat to travel deeper into the formation. Part of the injected CO2 is stored in the reservoir, with a proportion of 14.39%-17.12%, indicating the potential of CO2-assisted steam flooding in carbon sequestration. Based on the wide source and low cost of CO2, it has advantages in waste gas utilization and heavy oil reservoir development.

Application of Inter-Well Connectivity Analysis with a Data-Driven Method in the SAGD Development of Heavy Oil Reservoirs

The development of heavy oil reservoirs in China is of great significance to safeguard national energy security, but great challenges are faced due to the complex and heterogeneous reservoir properties. Inter-well connectivity analysis is critical to enhancing the development performance, as it is a good way to interpret fluid flow and provides a theoretical basis for injection-production optimization. Data-driven deep learning methods have been widely used in reservoir development and can be employed to develop surrogate models of injection and production and to infer inter-well connectivity. In this study, the model performance of a recurrent neural network (RNN) and its four variants were evaluated and compared in a temporal production prediction. The comparison results showed that bidirectional gated recurrent unit (Bi-GRU) is the optimal algorithm with the highest accuracy of 0.94. A surrogate model was established to simulate the inter-well connectivity of steam-assisted gravity drainage (SAGD) in the research area by utilizing the Bi-GRU algorithm. A global sensitivity analysis method, Fourier amplitude sensitivity testing (FAST), was introduced and combined with the surrogate model to explain the influence of the input variables on the output variables by quantitatively calculating the sensitivity of each variable. Quantitative results for the inter-well connectivity of SAGD were derived from the sensitivity analysis of the proposed method, which was effectively applied to typical linear patterns and five-spot patterns. Inter-well connectivity varied from 0.1 to 0.58 in test applications, and mutual corroboration with previous geological knowledge can further determine the distribution of the interlayer in the reservoir. The workflow proposed in this study provides a new direction for analyzing and inferring the inter-well connectivity of SAGD in Northeast China heavy oil reservoirs.

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.

In-Situ Steam Generation Using Mist Water-Air Injection as Enhanced Oil Recovery and Energy Efficiency Process: Kinetic Modeling and Numerical Simulation Approach

Summary In the current energy transition era, oil exploitation and especially the development of heavy oil reservoirs are facing big challenges to overcome the possible limitations in terms of economy (oil price), energy efficiency, and carbon footprint. Particularly, thermal enhanced oil recovery processes need to be re-evaluated in an attempt to harness the injected and produced energy. In that sense, Ecopetrol is evaluating new strategies to optimize the current steam injection process using different hybrid technologies from laboratory to field scale. One of the most attractive initiatives is evaluating the in-situ steam generation using mist water-air injection. This process involves simultaneous air and water injection into the formation through a set of nozzles. It looks to use part of the in-situ oil as a fuel, using the reservoir not only as a tank of energy but also as a steam generator. The main contribution of the technique concerning conventional steam generation is the use of the heat from the combustion of the residual oil to generate an in-situ steam front to transfer the uncontacted oil. This is reflected in reduced carbon dioxide (CO2) emissions, reduced fuel and water requirements, and increased oil production and net energy recovery. This article describes the methodology, results, history matching, and kinetic modeling of experimental evaluations and the upscaling of the experimental observations to a representative sector model from a Colombian heavy oil field. Results are described in terms of incremental oil recovery, energy efficiency, and carbon intensity compared with the baseline (a traditional steamflooding scenario). The technology of in-situ steam generation using mist waterair injection led to benefits in terms of better energy use and reducing the external fuel dependency for steam generation at the surface. Additionally, it was possible to identify improvements in incremental oil recovery (around 90%), energy efficiency (about 10 times less energy required to produce 1 m3 of oil), and reduction in carbon intensity (up to 91%) considering as baseline a conventional steamflooding scenario. These results will be key input parameters for designing and commissioning future applications in the Colombian fields.

In-situ emulsification synergistic self-profile control system on heavy oil reservoir development: Prescription construction and EOR mechanism investigation

Water flooding is a vital method used for developing heavy oil reservoirs. However, the fingering phenomenon is common because of the significant difference in water-oil mobility ratio, resulting in limited sweep efficiency and a low cumulative recovery factor. Viscosity reduction through emulsification and profile control using foam is of great potential to enhance oil recovery (EOR) in water flooding of general heavy oil reservoirs. The present work constructed an effective in-situ emulsification synergistic self-adjusting profile control system based on these two EOR pathways and investigated the performances of the proposed system, such as viscosity reduction via emulsification, foam plugging, and synergistic oil displacement. The results show that sodium octadecyl phenol polyoxyethylene ether sulfonate-4 (JNPM) with sound viscosity reduction, profile control, and oil displacement effects were synthesized through chlorination and sulfonation reactions. JNPM can reduce the oil-water interfacial tension and promote the emulsification of heavy oil in an effective way. It forms an unstable micron-scale oil-in-water emulsion, which is easy to induce oil-water separation of the produced fluid. The reduction in viscosity for JNPM exceeds 90%, whereas the foam produced by JNPM can adequately reduce the relative permeability of the displacement medium, and it is found that the resistance factor is higher than 25. The EOR mechanisms of JNPM include the following aspects. JNPM foam fluid has a stable plugging capability on the channeling channels of the displacement media, such as water and gas, which forcefully increases the residual oil sweep efficiency. JNPM peels off the residual oil on the pore wall through emulsification, thus the oil washing efficiency is improved. The droplets of oil formed by emulsification can block the channeling channels through the Jamin effect to further increase the conformance efficiency. In addition, when the small droplets deform and pass through the pores, they can sweep away the residual oil by dragging and entraining effects. The contributions of viscosity-reducing emulsification and foam plugging to EOR are 26.4% and 12.0% respectively during the viscosity-reducing foam flooding of JNPM.

Steam Cavity Expansion Model for Steam Flooding in Deep Heavy Oil Reservoirs

Steam flooding is crucial for the development of heavy oil reservoirs, and the development of the steam cavity significantly determines the efficiency of steam flooding. Previous studies have elucidated the concept of steam overburden and pseudomobility ratio; however, the thermal energy loss in deep heavy oil reservoirs during steam injection needs further investigation. Therefore, in this study, the vapour–liquid interface theory and mathematical integration were used to establish a steam cavity expansion model. The wellbore heat loss rate coefficient, steam overlay, and pseudomobility ratio were used to accurately describe the development of the steam cavity in deep heavy oil reservoirs. The proposed model was experimentally validated, and it was observed that the model could accurately reflect the actual mine conditions. In addition, the pressure gradient distribution of the steam belt and the heat dissipation areas of the top and bottom layers of the steam cavity were evaluated. The results showed that the influence of the wellbore heat loss rate coefficient on the pressure gradient of the oil layer was primarily in the range of 5–20 m away from the steam injection well. Furthermore, it was observed that the pseudomobility ratio is inversely proportional to the development of the steam cavity. As the wellbore heat loss rate coefficient increased, the wellbore heat loss increased. The larger the area ratio, the more pronounced the steam overlay phenomenon, and the large area ratio does not meet the development requirements of the steam chamber. The research closely combines theory with production, and the results of this study can help actual mines by providing theoretical support for the development of deep heavy oil reservoirs.

A Study on the Adaptability of Nonhydrocarbon Gas-Assisted Steam Flooding to the Development of Heavy Oil Reservoirs

In view of the serious heat loss in the process of steam injection for heavy oil recovery, nonhydrocarbon gas combined with steam has attracted much attention in recent years to realize the efficient development of heavy oil. Due to the wide variety of nonhydrocarbon gases, their performance in pressurization, dissolution, viscosity reduction, and heat loss decrease is changeable. In this paper, four groups of one-dimensional physical simulation experiments on different nonhydrocarbon gas-assisted steam flooding methods were carried out, and the effect on oil displacement characteristics under high temperature and pressure conditions was studied. Moreover, the differences in N2, CO2, and flue gas in energy supplementation, heat transfer, and oil recovery efficiency were also analyzed. The results showed that the three nonhydrocarbon gas-assisted steam flooding methods could significantly improve the oil displacement efficiency, which was specifically embodied as a faster oil production rate and longer production period. Compared with pure steam flooding, the recovery was increased by 12.13%, 16.71% and 13.01%, respectively. The effects of N2 in energy supplementation and heat transfer reinforcement were the greatest among the three nonhydrocarbon gases, followed by those of flue gas, and the CO2 effects were the worst. The temperature at the end of the sandpack model increased by 14.3 °C, 8.8 °C and 13.1 °C, respectively. In addition, CO2-assisted steam flooding had a prominent oil recovery effect, and the oil content of the sands in the front and middle of the model was significantly lower than that of other displacement methods. Most importantly, combined with the analysis of the remaining oil in the oil sands after displacement, we explained the contrasting contradictions of the three non-hydrocarbon gases in terms of recovery and energy supply/heat transfer, and further confirmed the gas properties and reservoir adaptability of the three non-hydrocarbon gases. The results may provide a theoretical basis for the selection of nonhydrocarbon gases for heavy oil reservoirs with different production requirements.