Development Of Heavy Oil Reservoirs Research Articles

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.

Theoretical Research on the Movement Law of Water Cone Behavior in Heavy Oil Reservoirs with Bottom Water

Aiming at the unclear reorganization of a water cone shape, its sweep range, and water saturation distribution of horizontal well in heavy oil reservoirs with bottom water, a mathematical method was proposed in this paper to establish a microtube model and physical model with the starting pressure gradient (SPG) to study the water cone behavior. The results showed that the different water-cut stage, mobility, depth from oil-water interface (DOWI), and liquid production strength have an obvious impact on water cone behavior. Moreover, we found an interesting phenomenon on an extreme point in water saturation derivation among water cone, which could be a reason for further adjustment. Finally, we confirmed the calculation results with physical simulation, which is highly consistent. The new method proposed in this paper was significant in the water cone behavior study and has a broad application in heavy oil reservoir development in the future.

An integrated framework based on deep learning algorithm for optimizing thermochemical production in heavy oil reservoirs

The development of heavy oil reservoirs with active edge and bottom water is one of the most challenging problems in petroleum engineering. In response to the limited thermal recovery of these reservoirs, a multi-phase and multi-component numerical simulation model for thermal and chemical recovery is proposed. An edge-water assisted chemical flooding (EAC flooding) is proposed, which can improve oil displacement efficiency and sweep efficiency by rational utilization of edge-water energy when compounding multi-component chemical system. Then, a deep reinforcement learning algorithm is proposed to predict dynamic production parameters and determine the optimal working system to maximize the oil recovery according to the above mathematical model. The deep reinforcement learning (DRL) model can predict the dynamic production curves according to given states with optimal strategy. At the same time, the proposed model can determine the best conversion timing from cyclic steam stimulation to EAC flooding. Finally, the DRL model can automatically obtain the optimal working system, effectively improving the oil recovery while considering the economic benefits. Thus, the DRL model can solve traditional numerical simulation's time-consuming and labor-intensive challenges and accurately give the optimal working system for developing heavy oil reservoirs with edge water in the field.

Experimental investigation on the SiO2 nanoparticle foam system characteristics and its advantages in the heavy oil reservoir development

In order to explore the influence characteristics of SiO2 nanoparticles on the SDS foam flooding in the heavy oil reservoir, in this work, CMC was used as the dividing boundary to prepare foams with different concentrations of nanoparticles and surfactants. Through experiments, the influence laws of nanoparticles on the foam were discussed, and the development process of foam flooding was simulated to study the influence mechanisms of nanoparticles and surfactant concentration on foam flooding. The results showed that the nanoparticles endowed the foams with rigidity, increased the viscosity, reduced the drainage velocity and interfacial energy, and optimized the half-life and viscoelastic modulus of the foam. These changes made the foam structure denser with better strength and stability, equipped it with better pore plugging ability and displacement mobility ratio, which optimized sweep efficiency while generating larger displacement pressure differentials. Finally, the heavy oil recovery rate of nanoparticle foam flooding reached more than 62%, which was much better than those of SDS foam flooding and water flooding. In addition, due to the synergistic effect of surfactants and nanoparticles, foam and heavy oil formed the foamy oil emulsion during the development process, which improved the oil mobility and further optimized the displacement mobility ratio. This emulsification mechanism reduced the heavy oil development difficulty, which was the key that foam flooding was superior to water flooding in the field of heavy oil development.

Effect of secondary water body on the in-situ combustion behaviors

In-situ combustion (ISC) is an effective alternative method for the development of heavy oil reservoirs, especially in the later stage of steam injection and a large majority of high water-saturated channels have been formed during this phase. The water-saturated channels, also known as secondary water body (SWB), is regarded as a sensitive factor to the ISC performance. The effect of the SWB with different scales and locations was investigated by using combustion tube experiments. Results show that the existence of SWB is conducive to improving the propagation speed of combustion front combined with the reduction of combustion stability during the ISC process. As combustion front propagates to the SWB, the temperature is quickly decreased accompanied by an unstable propagation process, which inevitably induces the significant reduction of the O2 availability and COx emission concentration. Additionally, oversized SWB would lead to a worse combustion process with much lower COx concentration and O2 availability or even fall into an extinguishment process. Better combustion performance and oil recovery factor are obtained when SWB has large spacing to the gas injection well or exists in the lower layer. Whereas the premature O2 breakthrough and unstable fire front propagation are generated if the SWB is close to the gas injection well or forms in the upper layer. The findings of this study are significant for better understanding the ISC performance with the consideration of SWB in heavy oil reservoirs.

Study on the Effect of Threshold Pressure Gradient on Remaining Oil Distribution in Heavy Oil Reservoirs

Due to the spatial network structure, heavy oil has a high threshold pressure gradient when it flows through porous media, and the threshold pressure gradient plays a crucial role in the distribution of remaining oil. In previous study, the common methods to measure the threshold pressure gradient include the microflow-established differential pressure (MFEDP) method, capillary equilibrium method, and the percolation curve fitting method. In this study, a sample from the SZ36-1 oilfield was analyzed for the basic physical properties based on the comparison of the previous measurement to study the influence of mobility on the threshold pressure gradient and then an independently developed numerical simulator was established to study the effect of the threshold pressure gradient on the remaining oil distribution considering the permeability range, crude oil viscosity, well network deployment, well spacing, and fluid recovery rate. The results show that the SZ36-1 oilfield fluid belongs to Bingham fluids with yield stress and the mobility having an exponent relation to the threshold pressure gradient based on the measurement of the MFEDP method. Considering the threshold pressure gradient of heavy oil, the uneven distribution of remaining oil is intensified and the remaining oil is enriched. This study provides a reference for efficient development of heavy oil reservoirs.

W/O emulsions generated by heavy oil in porous medium and its effect on re-emulsification

Water/hot water flooding and steam stimulation are usually used for heavy oil recovery. However, W/O emulsions are generated when heavy oil and water flow in porous medium of formations, which can seriously restrict the recovery effect in the middle or late stage. First, the influence of the W/O emulsion on efficient heavy oil recovery is analyzed by the production dynamics and produced fluid emulsified states of oilfields. Then, the W/O emulsion generation process during heavy oil entrapment and water flooding recovery was simulated. The effects of permeability, porous medium shearing distance and heavy oil viscosity on the emulsified state of W/O emulsions were studied. The properties of W/O emulsions were tested. Before reaching the final emulsified state, the lower the permeability and the longer the porous medium shearing distance, the more fully emulsified of the W/O emulsion. In the final emulsified state, the droplet sizes of the W/O emulsions generated by different viscosities of heavy oil are basically the same at the same water content. As the water content increases, the W/O emulsion droplet size grows first, then tends to stabilize, and finally stabilizes at between 2 and 3 μm. The viscosity of the W/O emulsion increases as water content increases and its viscosity increases significantly at high water contents. The lower the viscosity of dehydrated heavy oil is, the greater the increase of the viscosity of W/O emulsion increase. The viscosity of 70% the water content W/O emulsion is more than 15 times that of the dehydrated heavy oil. Finally, the effects of the water content, surfactant concentration, oil–water ratio on the emulsified state, droplet size distribution and its fluidity in porous medium were studied by simulating the re-emulsification process of W/O emulsion and surfactant solution. A W/O/W emulsion would formed by re-emulsification of the W/O emulsion and surfactant solution. As the water content of W/O emulsion increases, the droplet size of the W/O/W emulsion formed by re-emulsification increases, and its fluidity in porous medium decreases. The average emulsion droplet size (50% water content) after re-emulsification is 6.29 times that of emulsions formed by dehydrated heavy oil, and the apparent viscosity in porous medium is 15.05 higher. This study provides significant information for understanding the key issues in the efficient development of heavy oil reservoirs throughout their life time and the research and development of high-efficiency emulsion flooding systems.