Oil Recovery Research Articles

Toxicity and environmental aspects of surfactants

Abstract As the single largest class of specialty chemicals, surfactants are consumed in huge quantities in our daily life and in many industrial areas. In the past, the attention was focused entirely on technical performance. However, starting from the 1970s and 80s, surfactant related environmental concerns have become the main driving force to upgrade surfactant production technology to make more benign or “greener” products. For this reason, environmental issues, dermatological effects, and oral toxicity are the main priorities when surfactants are considered for a specific purpose. In this paper, we present five cases to demonstrate how the surfactant industry tackles these challenges to mitigate the environmental and health effects associated with surfactant consumption. We also discuss the important role played by surfactants in a current carbon capture and storage (CCS) strategy to reduce the CO2 level in the atmosphere. Surfactant-based stable CO2 foam flooding is a well-established enhanced oil recovery technique. It has been considered to be an economically realistic procedure to sequester large amounts of CO2 in geological formations.

Synthesis of novel green nanocomposites by considering enhanced oil recovery and asphaltene adsorption effectiveness in calcite and dolomite formations

Asphaltene deposition is known as the main issues in reservoirs, which causes formation damage in reservoir. This research investigated the effects of a newly introduced green nanocomposites, namely eucalyptus/CuO/Fe3O4/xanthan nanocomposites (EC-NCs), on the inhibition of asphaltene precipitation in calcite and dolomite formations. First, at two time steps of 48 and 96 h, asphaltene adsorption on EC-NCs surfaces was examined through scanning electron microscope (SEM) tests in both calcite and formation tests. Moreover, asphaltene adsorption on the surface of EC-NCs was confirmed through isotherm models including Langmuir and Freundlich and the interfacial tension between CO2 and oil. Finally, a series of static and dynamic tests were performed at the highest adsorption pressure points, including 4200, 3950, and 3700 psi, and at the highest adsorption time step, i.e., 96 h, and the effects of asphaltene adsorption were seen on permeability reduction and asphaltene precipitation. EC-NCs exhibited superior efficacy in both asphaltene adsorption and precipitation inhibition. Two separate pressure changes were observed, and the ratios of the interfacial tension slope in the 2nd to the 1st regions [1st: 200–2700 psi, 2nd:2700–4200 psi] were changed from 19.44 % to 25.00 % and 29.74 % in 48 and 96 h, respectively, and this confirms that asphaltene had indeed adhered to the surface of the EC-NCs. Moreover, at 48, and 96 h, the size reductions of particles in SEM for calcite and dolomite were (29.27 %, 56.81 %), and (59.09 %, 62.25 %), respectively, which shows asphaltene adsorption was more efficient in dolomite formation, and in 96 h.

A Relaxation Scheme for the Simulation of Two‐Phase Flows With Inaccessible Pore Volume in Polymer Flooding

ABSTRACTThe simulation of polymer injection in a reservoir is of paramount importance in enhanced oil recovery. Despite decades of research, the computation of polymer flows in porous media remains a challenging task. The main difficulty lies in the necessity to take into account the effect of inaccessible pore volumes (IPV), for which standard closure laws give rise to a weakly hyperbolic or even non‐hyperbolic system. In the latter case, exponential instabilities may appear at the continuous level, which must be addressed at the discrete level so as to prevent a premature stop of the numerical simulations. The notion of IPV was introduced by engineers in order to account for the following observation: when a polymer solution is injected into an initial core saturated with water, the breakthrough of the polymer at the exit occurs before that of the water in which it is injected. It seems that due to their large size, the polymer molecules cannot insinuate themselves into all pores as well as water. Having less volume to flood, the polymer molecules see their speed increased, hence the ad hoc acceleration factor associated with the polymer. In this work, we propose a relaxation method that guarantees some practical robustness for all IPV laws. This is achieved by replacing the original system by a relaxation model which is always hyperbolic. The designed relaxation model involves two parameters which enable us not only to adjust the correct amount of numerical dissipation, but also to ensure positivity for some critical quantities such as water saturation and polymer concentration. Extensive numerical tests are performed in order to compare the relaxation scheme to the more classical upwind scheme for several IPV laws.

Discrepancy in oil displacement mechanisms at equivalent interfacial tensions: Differentiating contributions from surfactant and nanoparticles on interfacial activities

Discrepancies in oil displacement mechanisms at equivalent interfacial tensions were principally explored in the current study, with a novel emphasis on distinguishing the contributions of surfactants and nanoparticles in interfacial activities. The hypothesis was that if both chemicals exhibit similar interfacial activities, the oil displacement outcomes at the capillary scale should be consistent. Otherwise, differences would indicate distinct interfacial behaviors. Fluid displacement experiments were conducted using a two-dimensional micromodel, where nanofluids and surfactant solutions were tested at equivalent interfacial tensions. In the high interfacial tension pair (20 mN/m), the surfactant solution displaced oil more efficiently and rapidly than nanofluids, achieving greater ultimate oil recovery. This difference was attributed to the effective reinforcement of capillary forces in the surfactant system, which drove the displacement process. In contrast, the nanofluids did not achieve the same level of performance due to their limited ability to modify interfacial forces. This finding highlighted the two chemicals’ fundamentally different interfacial activities and oil displacement mechanisms. Furthermore, in the lowest interfacial tensions pair, where the surfactant achieved 6.5 mN/m and the nanofluids 15.6 mN/m, both systems unexpectedly displayed similar oil displacement efficiencies and fingering-like behaviors. This similarity, however, arose from distinct underlying mechanisms: capillary instability drove fingering in the surfactant system, while expansive layer flow induced fingering-like in the nanofluids. These findings challenge the assumption that reducing interfacial tension with nanoparticles is the primary mechanism in enhanced oil recovery (EOR). The study highlighted the need for a more refined understanding of the action of nanoparticle interfacial activities within EOR processes. To further validate these insights, future research should scale up fluid displacement studies to Darcy’s scale using core-flooding tests, enabling a more comprehensive examination of complex two-phase flow dynamics.

Study on the Impact of Porous Media on Condensate Gas Depletion: A Case Study of Reservoir in Xihu Sag.

During the depletion and pressure reduction process in condensate gas reservoirs, the precipitation of condensate oil transforms the single-phase gas flow into a two-phase gas-liquid flow, significantly reducing the permeability. Currently, microscopic studies of the phase behavior of condensate gas in porous media mainly focus on observing and describing the occurrence of condensate oil, lacking quantitative calculations and direct observations of condensate oil throughout the entire depletion cycle. This paper uses a microvisualization method to simulate the depletion process of condensate gas reservoirs. Condensate gases with oil contents of 175.3 and 505.5 g/cm3 were prepared by mixing methane, ethane, hexane, and decane in specific proportions. Pore structures were extracted from thin sections of real core casts, and microfluidic chips with a minimum pore diameter of 20 μm and an areal porosity of 20.75% were fabricated by using a chemical wet etching method. Subsequently, microfluidic condensate gas depletion experiments were conducted with chip images recorded during the depletion process. Grayscale analysis of the depletion images was performed using ImageJ software to quantitatively calculate condensate oil saturation and recovery rates, analyzing the effects of different condensate oil contents on condensate gas depletion, and comparing the differences between depletion in porous media and in a PVT cell. The conclusions drawn are as follows: the dew points of high and low in the porous media are 3.15% and 1.85% higher than those in the PVT cell, respectively. In the early stages of depletion, condensate oil saturation in porous media is higher than that in the PVT cell, while in the middle to late stages, condensate oil saturation in porous media is lower than that in the PVT cell. The condensate oil recovery rate in porous media is significantly higher than the depletion recovery rate in the PVT cell. Condensate oil tends to precipitate and disperse at blind ends and corners, while it easily forms patches in mainstream large pores.

Analysis of Entropy Optimization in MHD Flow of Non-Newtonian Nanofluids with Chemical Reaction and Thermal Energies

Investigation of nanofluid flows under various conditions is becoming fascinating research due to its numerous applications in many science and engineering fields such as solar energy, geothermal energy, water purification, glass blowing, enhanced oil recovery, petroleum production and food processing. For the present requirements in thermal energy applications, this mathematical model is considered to explore the diffusion and heat source effects on the flow of conductive Casson and Maxwell nanofluids in a porous medium on an elongating sheet with a chemical reaction. Further, the effects of viscous dissipation and thermal radiation are also examined. Moreover, the entropy generation is analyzed since this approach is employed in solar energy exchangers. The governing equations and the corresponding boundary conditions are constructed. This system of partial differential equations (PDEs) is changed into a system of nonlinear ordinary differential equations (ODEs) with the help of a suitable transformation and then solved numerically by the bvp5c MATLAB package. The influences of the physical parameters on the flow phenomena are discussed and presented through figures and tables. This analysis explains that the Casson fluid flow has a higher velocity field than the Maxwell fluid flow. The Nusselt number becomes higher as the Dufour numbers increase. It has also been noticed that increasing the Brinkmann number improves the entropy and, an increase in radiation enriches the temperature profile. The concentration of the fluid is decreased for the increasing values of the higher-order chemical reaction parameter. Furthermore, comparisons of the current results were conducted for limiting examples of the problem and found to be in good agreement with existing results in the literature.

Pore-scale modeling of wettability alteration coupled two-phase flow in carbonate porous media

The Middle East marine carbonate reservoirs are the primary targets for global crude oil exploration and production. In contrast to the clastic rock reservoirs, the marine carbonate reservoirs have undergone more complicated deposition, diagenesis and transformation, and the rock surface tends to be oil-wet or mixed-wet. One of the most effective methods for enhancing oil recovery in marine carbonate reservoirs is the use of an ion matched (IM)-surfactant (S) system to alter the wettability of rock surfaces. In this paper, we propose a microscale mathematical model of wettability alteration-coupled fluid flow by considering oil–water two-phase flow, wettability alteration, solute advection- diffusion and surfactant adsorption. The proposed microscale mathematical model is solved using the multi-component lattice Boltzmann model, and its accuracy is further verified. Finally, the effects of displacing fluid, ion-matched water concentration and surfactant concentration on oil mobilization at pore-scale are studied. Results show that, ion-matched water has a positive effect on wettability alteration, and typically shifts the cross-point of oil–water relative permeability curve to the right. The concentration of ion-matched water primarily affects fluid morphology of the wetting-phase and has little effect on phase permeability. After adding surfactant to the ion-matched water, the Euler coefficient of oil-phase gradually increases as the displacement continues, a large amount of remaining oil is gradually dispersed into scattered oil droplets and the oil-phase relative permeability is further improved.

Simulation-Based Optimization Workflow of CO2-EOR for Hydraulic Fractured Wells in Wolfcamp A Formation

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO2 huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

Study on the preparation of magnetic Janus nanofluids and oil displacement mechanism

Magnetic nanomaterials, known for their eco-friendliness, low toxicity, strong magnetic response, and reusability, have seen significant advancements in enhancing oil recovery. In this study, the surfactant and magnetic Janus nanoparticles (MJNP) were evaluated and optimized through Fourier transform infrared spectroscopy, ζ potential test, scanning electron microscope, emulsion performance evaluation and other analysis, so as to develop magnetic Janus nanofluids (MJNF). Study the flow behavior and enhanced oil recovery mechanism of this nanofluid in porous media through nuclear magnetic resonance (NMR) and numerical simulation methods. The results showed that when the concentration of surfactant (LAD-30) was 0.08%, the maximum water content of emulsion was 80%, and the viscosity increased by more than 90000%. In addition, when the MJNP concentration is 400 ppm or higher, a stable emulsion is formed at 90 °C. NMR experiment shows that through MJNF oil displacement, the oil recovery of small and medium-sized pores is significantly improved by 25.9% and 18.3%, which indicates that high viscosity emulsion can be formed in situ after MJNF injection, thus achieving consistency control. In addition, the numerical simulation results also found that MJNF injection can improve the oil-water saturation in the pore volume and enhance oil phase flow. The research results provide a new understanding for EOR of emulsion flooding.

A coupled displacement-pressure model for elastic waves induce fluid flow in mature sandstone reservoirs

Elastic (seismic) wave stimulation is considered one of the unconventional enhanced oil recovery (EOR) methods. Increasing water quantity in the high permeability layer of a mature oil reservoir is highly challenging and can significantly decrease the ultimate recovery due to the reservoir heterogeneity. Using seismic waves can be considered low-cost, environmentally friendly, and illuminates the entire reservoir size compared to conventional EOR methods. A numerical model is developed by extending the Quintal approach for seismic attenuation due to wave-induced fluid flow (WIFF) to incorporate capillary pressure in partially saturated porous media and shift undrained boundary conditions to exclude external flow stress for drained boundary conditions. Therefore, the fluid distribution due to the capillary effect makes the developed finite element method (FEM) u-p model more widely applicable for oil recovery in mature reservoirs. A two-layer partially saturated media was subjected to compressive seismic stress at low frequency (3 Hz). The results indicated that the vertical displacement gradients of the bottom and upper layers decline with excitation time for both fully and partially saturated media. On the other hand, partially saturated pore pressure gradients of both the upper and bottom layers have higher amplitudes with excitation time than fully saturated pore pressure gradients due to the influence of capillar pressure. The cumulative crossflow oil volume for 180 days of continuous stimulation was 1176 bbl, 1032 bbl, and 648 bbl in low permeability layers: 200 md, 100 md, and 50 md, respectively. Therefore, the developed model has the potential for field-scale EOR applications. The study also suggests coupling elastic EOR with CO2 flooding to recover more oil due to increasing fluid mobility and relative permeability to oil in low-permeability reservoirs or tight formations.

The Formation Mechanism of Residual Oil and Methods of Enhanced Oil Recovery in a Fractured Low-Permeability Metamorphic Rock Reservoir in Bohai Bay

The oil reservoirs of the metamorphic rocks in Bohai Bay have geological characteristics such as low matrix porosity and permeability, developed natural microfractures, which result in the injection water rapidly advancing along fractures, a fast increase in the water content, and difficulties in extracting the remaining oil. In order to reveal water channeling and the residual oil formation mechanisms in fractured low-permeability reservoirs and solve the water channeling problem, we first analyzed the reservoir development status, then studied the formation mechanism of residual oil using a microfluidic chip device, and formed a method of hierarchical control to effectively control the water channeling problem of fractured reservoirs and maximize the displacement of residual oil. The results show that (1) Due to the low permeability of the reservoir matrix, a large amount of injected water flows along the fracture channel, which leads to the long-term high water cut of some oil wells and the retention of a large amount of crude oil in the matrix. (2) The results of microfluidic experiments show that the distribution of residual oil after water flooding mainly includes five types: blind end of the pore throat, columnar, cluster, flake and film, and residual oil. Among them, sheet-like and clustered residual oil are dominant, accounting for 75~85% and 10~13%, respectively. (3) Based on the characteristics of fracture development in buried-hill reservoirs, a hierarchical control technology of “gel particle + liquid crosslinked gel system” is established. The field application effect predicted that the input–output ratio was 1:3. This study provides a reference for the comprehensive treatment of water channeling in the same type of offshore fractured low-permeability metamorphic rock reservoirs.

Glycerol Carbonate as an Emulsifier for Light Crude Oil: Synthesis, Characterization, and Stability Analysis

This study focuses on the synthesis and application of glycerol carbonate (GC) as an emulsifier for light crude oil. GC was synthesized from glycerol and dimethyl carbonate via transesterification, achieving a 90% yield. Characterization through 1H-NMR, 13C-NMR, and FT-IR confirmed its structure. The emulsification properties of GC were tested by mixing it with light crude oil and water, demonstrating effective emulsification and forming stable emulsions. Stability tests with GC concentrations of 60/40, 70/30, and 80/20 revealed that emulsions remained stable for over 24 h. A particle size analysis indicated that higher GC concentrations produced smaller droplet sizes, enhancing the emulsification efficiency. This study highlights the potential applications of GC in oil spill remediation and enhanced oil recovery, emphasizing its biodegradability and low toxicity as environmental benefits. Overall, GC is presented as an effective and eco-friendly emulsifier for light crude oil, offering stable emulsions and promising industrial applications.

Optimization of Cassava-Peel Derived Nanostarch Via Sulphuric Acid Hydrolysis Using Taguchi Method

Untreated cassava peel waste generated during harvesting and processing poses significant environmental challenges. Synthesis of starch nanoparticles from cassava peels for various applications offers a sustainable solution to waste reduction and contributes to environmental conservation. The unique characteristics of nanostarch such as thermal stability, high solubility, non-toxicity, and low cost enable its application in the food industry, cosmetics, enhanced oil recovery, and textiles. The current study employed the Taguchi method design to optimize sulphuric acid hydrolysis in synthesizing cassava peel-derived nanostarch. Additionally, the derived cassava peel nanostarch was characterized using Fourier Transform Infrared Spectroscopy (FTIR). Starch was extracted from cassava peels, followed by synthesizing starch nanoparticles via sulphuric acid hydrolysis. Optimization of nanostarch synthesis was based on randomized experimental runs using the Taguchi method generated by the Minitab software, with the experiments conducted in duplicates. The optimum conditions for the experiment were found to be 3 hours, at 25°C using an H<sub>2</sub>SO<sub>4 </sub>acid concentration of 2M. These conditions produced a yield of 92.28%. ANOVA analysis identified sulphuric acid concentration as the most significant factor that affected cassava nanostarch yield, with p-values of 0.026 and 0.003 for the signal to noise (S/N) ratios and means, respectively. The least significant factor based on the analysis was the hydrolysis time. However, according to the S/N ratios main effect plot, the most optimum conditions predicted by the Taguchi method design was 9 hours, 25°C using H<sub>2</sub>SO<sub>4 </sub>acid concentration of 2M. A confirmation experiment conducted at 25°C, using an H<sub>2</sub>SO<sub>4 </sub>acid concentration of 2M for 9 hours gave a nanostarch yield of 97.01%. In conclusion, the Taguchi method design identified sulphuric acid concentration as the most significant factor in synthesizing cassava peel-derived nanostarch via acid hydrolysis.

CO2 foam structure and displacement dynamics in a Hele–Shaw cell

The substitution of CO2 gas with CO2 foam for improved mobility control has recently attracted research attentions in enhanced oil recovery (EOR) as well as aquifer and soil remediation. However, the interplay between CO2 foam properties and oil displacement remains less investigated. In this work, using clear visualizations, we systematically investigate the dynamic advection-dominated foam morphology, its corresponding viscosity, and the efficiency and dynamics of oil displacement process by CO2 foam in a Hele–Shaw cell under the effects of gas ratio (Rg), fluid injection rates (Qt), and surfactant type. Clear visualization enables particle image velocimetry to calculate actual, rather than nominal, foam velocity that significantly affects the estimated foam viscosity. Our results demonstrate that at elevated gas ratios under constant total injection rate, larger and more uniform bubbles with less number density and greater interfacial area are obtained. Increasing the injection rates leads to finer foam texture at a constant gas ratio. Different foam structures have an impact on the foam viscosity, with a general increasing trend of viscosity for larger bubbles as Rg increases from 0.5 to 0.85. The higher the foam viscosity, the more stable displacement interfaces with less viscous fingers are observed, leading to improved sweeping rates. The green surfactants (saponin + Cellulose NanoFibers) provide foams with higher viscosity and, thus, more stable displacement interfaces. These findings highlight the important effect of Rg–dependent foam structure on its viscosity, which in turn is crucial for controlling the mobility of CO2 foam to maximize oil recovery rate during EOR processes.

Characterization and Inversion Method of Relative Permeability of Emulsion Flooding.

Relative permeability curves are one of the crucial factors that control the behavior of multiphase flow in petroleum reservoirs. Accurate prediction of the relative permeability curve involving emulsification and emulsion transport in emulsion flooding is vital to enhancing heavy oil recovery. In this study, a relative permeability characterization model including the emulsification mechanism and emulsion transport is developed, in which residual oil saturation and end-point permeability for water are parametrized as functions of emulsion concentration and capillary number. Based on the built characterization model, an inversion method (ensemble Kalman filter) is used to estimate the relative permeability curves of emulsion flooding. The inversion results of four sets of emulsion flooding experiments show that the errors of end points between the Johnson-Bossler-Neumann method and inversion method are less than 10%. For the continuous emulsification process in the in situ emulsion flooding tests, the inversed relative permeability curves shift between the upper and the inferior limits of the permeability. The error of residual oil saturation between the inversion and the experiment is less than 10%. In summary, this study demonstrates the feasibility of using the characterization model and inversion method to infer the relative permeability curves of emulsion flooding, which can aid in the predictions of multiphase flow in heavy oil reservoirs.

Study of cellulose nanocrystals -enhanced natural gas foam performance and profile control & oil displacement mechanism

ABSTRACT To address the poor performance of conventional natural gas foam flooding in the tight conglomerate reservoirs of the Mahu region in Xinjiang, a high-activity green material, cellulose nanocrystals (CNC), was introduced to improve foam performance based on a conventional AOS+SDS foam system. However, the impact of CNC on the performance of the conventional foam system and the synergistic effects between CNC and surfactants are not yet clear. Therefore, this study evaluates the improvement effects of CNC on foam performance from both macroscopic and microscopic perspectives by analyzing the foam composite index and the synergistic effects between CNC and surfactants. The study also investigates the factors affecting foam performance and uses a planar visualization model to evaluate the enhanced gas foam flooding effects from a microscopic mechanism perspective. The results indicate that CNC increases the foam composite index by 26,850 mL·min on a macroscopic level. Microscopically, it makes the foam more compact, thickens the foam liquid film by 0.1 mm, improves the wettability reversal by 10%, and reduces the oil-water interfacial tension by 0.26 mN/m. After mixing 1 vol% crude oil, the foam volume and half-life decrease by 12% and 4%, respectively. At reservoir temperature and pressure, the foam volume decreases by 12.7% and 10.5%, but the half-life increases by 4 hours and 3.7 hours, respectively. At formation water mineralization conditions, the foam volume and half-life decrease by 6.6% and 1.7 hours, respectively. In summary, it still has good performance under reservoir conditions. The visualization model demonstrates from a microscopic perspective that the foam system has good gas shutoff capability. After foam flooding, the gas sweep efficiency increases by 54.12%, and the foam flooding and subsequent gas flooding improve the crude oil recovery by 20.32%.

Study on Thermal Chamber Expansion of VH-SAGD Process Using CO2-Inducing Effect for Heavy Oil Reservoirs

In heavy oil thermal recovery processes, higher pressure usually leads to low dryness and expansion difficulty for the injected steam in thermal recovery processes, which will result in lower oil recovery and more carbon emissions. This paper proposed a new CO2-inducing method to accelerate the steam chamber expansion, based on a core flooding experiment and numerical simulation. First, the CO2 showed significant viscosity reduction at high pressure in the PVT test. In the core flooding experiment, the CO2 provided strong flow conductivity in porous media for the thermal flooding, as the CO2 pre-injection restrained the steam condensation. Using the CO2-inducing method, CO2 pre-injection before steam built a fast flow channel in a relatively higher permeability layer and reduced the thermal injection pressure by about 1.0~2.4 MPa. As a result, the steam overlap around the injection wells became slower and the gravity drainage process was able to heat and displace the heavy oil above the channel. Furthermore, the CO2 gas trapped at the top reduced heat loss by about 12.4%. The field numerical simulation showed that this new method improved thermal recovery by 7.5% and reduced CO2 emissions by about 18 million kg/unit for the whole process. This method changes the conventional thermal expansion direction by CO2 inducing effect and fundamentally reduces heat loss, which provides significant advantages in low-carbon EOR.

A prediction method of oil recovery for hot water chemical flooding in heavy oil reservoirs: Semi-analytical stream tube model

Abstract Chemical agents (polymer and surfactant) assisted hot water flooding is an effective means of enhancing oil recovery in heterogeneous and heavy oil reservoirs. The rapid prediction of oil recovery through hot water chemical flooding is very important. The stream tube model is a fast analytical method for predicting water flooding recovery, but it is not suitable for hot water chemical flooding. In this paper, a permeability distribution model for multi-stream tubes is established based on permeability variation coefficient using normal distribution function for reservoir heterogeneity, Using GOMPERTZ growth function model to characterize the changes in stream tube temperature, polymer viscosity, and surfactant concentration with injection volume, Using Brooks-Corey model to describe the influence of interfacial tension and temperature on the relative permeability curve. Finally, an analytical stream tube model for hot water chemical flooding of heavy oil reservoirs was established. The time discrete method is used to solve the model, then the graphs of the relationship between oil recovery and water cut are obtained. Compared with numerical simulation methods, the prediction error of oil recovery is less than 2%, and the calculation time is reduced by 89%. This model has been successfully applied to X oilfield. Based on historical fitting, it is predicted that hot water chemical flooding can enhance oil recovery by 6.3% compared to water flooding. This paper provides a fast calculation method for predicting and evaluating the effectiveness of hot water chemical flooding in heavy oil reservoirs.

Применение новых технологий кислотной обработки пластов для восстановления продуктивности пласта

Oil recovery, measured by the oil recovery factor (ORF), is a key indicator of the efficiency of oil production. In Russia, the ORF decreased to 0.3 while in the United States this indicator increased to 0.4. About 90% of Russian oil is produced by large holdings, the structure of reserves is shifting towards hard-to-recover, which requires the use of new methods to increase oil recovery. Primary and secondary production allows only 20-50% of oil to be extracted, what makes the use of tertiary methods necessary. The development of horizontal wells with multistage hydraulic fracturing contributes to the development of new field sites, but requires careful preparation of wells to minimize risks and cost increases. Cleaning the bottomhole area using acidic formulations is often the only cost-effective way to restore the productivity of a horizontal well. The improved method of acid composition reduction using a guar gel with delayed “crosslinking”, which ensures uniform treatment of all productive zones of the formation is considered in article. The technology allows for continuous multi-stage acid treatment, temporarily blocking highly permeable areas and increasing the coverage of acidic effects on poorly drained areas. The calculation of the diverter volume considers the average efficiency of the liquid after mini-fracturing, adjusting the volume depending on the efficiency of the liquid at each port.

Активизация пластовой микрофлоры для повышения нефтеотдачи

Constant optimization of technological processes of oil production is one of the integral parts of rational subsurface use. The study and implementation of new developments and technologies in the oil production process is primarily due to the economic effect. Methods of increasing oil recovery are of particular interest in the practical implementation of innovative technologies in the oil and gas industry. To date, a huge number of technologies have been developed and tested in field conditions aimed at preserving and increasing the volume of produced products, the classification of which is very diverse. The primary criteria for choosing a method or combination of methods of influencing a productive reservoir in order to increase oil recovery are the geological conditions of the productive horizon, as well as the composition and physico-chemical properties of reservoir fluids. Currently, of all the many methods of increasing oil recovery, the microbiological method is the least studied, as a result of which it is extremely rarely used in enterprises. The relevance of research on the effects of microorganisms on the reservoir rock is beyond doubt. The possibility of widespread application of oil recovery enhancement technology based on bacterial life processes is interesting both from the point of view of environmental safety and economic efficiency. One of the microbiological methods of increasing oil recovery is the activation of the existing reservoir microflora by feeding a nutrient medium into the reservoir. In the course of their vital activity, some types of bacteria are capable of destroying clay rocks, which entails changes in the filtration and capacitance properties of the reservoir rock and, as a result, the volume of products produced increases significantly. The advantage of this method is the absence of the need for forced “contamination” of the reservoir formation, since the necessary bacteria are already in it.