Oil Recovery Methods Research Articles

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.

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.

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.

Preliminary experimental study of low salinity effect on organic polar compounds desorption in Hassi Messaoud field-Algeria

Low salinity water (LSW) injection is a well-recognized enhanced oil recovery method that has proved to increase oil recovery. Despite its simple implementation and low cost, no experimental investigations have been reporting its application in Algeria’s oil fields. The present work investigates the impact of LSW injection and identifies the role of organic polar compounds on oil trapping in Hassi Messaoud oil field. The study involves adsorption/desorption experiments using acid/amine organic polar compounds dissolved in non-polar refined oil while employing rock drilling cuttings. Subsequent validation of desorption data is performed by employing crude oil in both Amott tests and micro-model displacement tests using various water salinity ranges. It was evident that at water salinities ranging from 1000 to 2000 ppm, the interfacial tension decreased to 10−2 mN/m, leading to favorable rock wetting behavior and increased oil recovery of 9.18% and 20.07% for amine and acid compounds, respectively. The wettability alteration mechanism was proposed as the main contributor since the actual interfacial tension of natural surfactant might not significantly impact oil recovery. The implementation of LSW injection in Algerian fields presents fresh prospects for future enhanced oil recovery projects.

Chemical enhanced oil recovery using carbonized ZIF-67 MOFs and sulfonated copolymers at high reservoir temperatures

Traditional nanoparticle and polymer-based enhanced oil recovery methods face challenges such as nanoparticle agglomeration and polymer adsorption, particularly at elevated reservoir temperatures. This study introduces hybrid polymeric nanofluids, combining carbonized Zeolitic Imidazolate Framework-67 (ZIF-67) with sulfonated copolymers to address these issues. Viscosity tests were conducted at 25 °C, 50 °C, 75 °C, and 90 °C, revealing a 39.67 % increase in viscosity at 90 °C, attributed to electrostatic and hydrogen bond interactions. For subsequent analyses—stability, adsorption, and core flooding—75 °C was selected as the representative high reservoir temperature. Stability assessments, confirmed via UV–Vis spectroscopy, demonstrated nanofluid durability over at least seven days. Carbonized ZIF-67 reduced polymer adsorption on rock surfaces, enhancing oil recovery and reducing environmental impact. Dynamic core flooding experiments showed a 45.8 % improvement in oil recovery by the hybrid nanofluid on carbonate rock samples. The hybrid nanofluid increased RF and RRF, improving the mobility ratio and redirecting flow to lower-permeability zones, reducing unswept oil and enhancing macroscopic sweep efficiency. Winsor Type III emulsification during the post-flooding phase of polymer-nanoparticle injection significantly improved trapped oil mobilization. Reduced contact angles from 170° to 100° altered the wettability, enhancing oil recovery. Carbonized ZIF-67 nanoparticles increased viscous forces, reduced capillary forces, and minimized polymer adsorption. The polymeric nanofluid achieved a capillary number of 1.0 × 10−3, two orders higher than that of polymer alone, resulting in superior performance. Injectivity optimization showed shear rates of 15.9 s−1 in 1700 mD cores and 79.8 s−1 in 80 mD cores, causing pressure drops of 15 psi and 1200 psi, respectively. This highlights injectivity challenges in 80 mD cores, while cores ≥ 290 mD are ideal for our polymer-nanoparticle hybrid applications.

Heuristic algorithm for calculating the component composition of recombination gas without an adapted equation of state

Background. To conduct laboratory research of projects of gas enhanced oil recovery methods, a large volume of reservoir system is required. Often its replenishment by depth and/or separator samples is not economically feasible. Therefore, the task of fluid recombination from wellhead liquid sample and natural gas simulator arises. Objective. To calculate the component composition of recombination gas under the conditions of the task. Materials and methods. The heuristic calculation algorithm uses the tools of: modeling, inverse problems of physics, set theory, mathematical programming. Special focus is given to its empirical and theoretical justification. Results. The paper considers the limitations of the thermodynamic method. The conditions of the problem to be solved are outlined and justified. The applied algorithm of the solution is formulated and derived. The efficiency of the algorithm for oil systems is experimentally confirmed. Conclusions. The work will be of interest for specialists in the field of laboratory research projects of gas enhanced oil recovery methods. The issues of improving the accuracy of the applied algorithm and its further development are still under discussion.

Modeling the impact of pH and reservoir temperature on the dissolution of quartz mineral due to oilfield chemical treatment

The petroleum industry frequently uses oilfield chemicals, such as corrosion inhibitors, scavengers, drilling fluid, and chemical enhanced oil recovery methods, to improve oil recovery. However, these chemicals can negatively impact the geochemical characteristics of the formation, potentially leading to facility failure and reservoir formation damage. A study using PHREEQC was conducted to predict the impact of reservoir temperature and pH on quartz rock dissolution under different temperatures and pH levels. The results showed consistent dissolving rates for quartz at different pH levels. The solubility of quartz minerals was slightly affected by the solution pH, suggesting that the process variable pH has little effect on the equilibrium rate. However, precipitation caused quartz to dissolve at a rate of 0.04 mmol.L−1.s−1 at 45 °C but increased to 0.07 mmol.L−1.s−1 at 65 °C in 0.8 s. As temperature increased, quartz and NaNO3 solution interaction reached equilibrium concentrations in 0.8 and 2.7 s. The study concluded that temperature significantly impacts quartz dissolution during interaction with sodium nitrate oilfield chemicals compared to pH. The PHREEQ software is a useful research tool for simulating rock-fluid interactions resulting in reservoir formation dissolution and precipitation, which can cause formation damage and sand production.

Synergistic enhancement of oil recovery: Integrating anionic-nonionic surfactant mixtures, SiO2 nanoparticles, and polymer solutions for optimized crude oil extraction

Enhanced oil recovery (EOR) methods are essential for optimizing oil extraction from modern reservoirs. This research delved into the synergistic impact of combining anionic and nonionic surfactant mixtures with silica (SiO2) nanoparticles (NPs) in sodium chloride (NaCl) solutions, alongside the added enhancement of polymers, to improve crude oil recovery. The study comprehensively evaluated stability, rheological characteristics, interfacial tension (IFT) behavior, wettability alterations, and EOR experiments using mixtures of sodium dodecyl sulfate (SDS) and triton X-100 (TX-100) surfactants. Scenarios both with and without SiO2 NPs in a base solution containing 3000 ppm NaCl and 2000 ppm xanthan gum (XG) polymer were examined. Core flooding tests were carried out on San-Saba sandstone core specimens with low permeability. The stability tests and dynamic light scattering (DLS) analysis were performed to assess the stability of NPs in low saline-surfactant-polymer solution. It was observed that NPs significantly reduced the IFT between the test solutions and crude oil, with nanofluids exhibiting satisfactory stability at a 0.4 wt% SiO2 NPs concentration. Core flooding studies demonstrated a synergistic interaction between NPs and the binary surfactant-polymer mixture, resulting in substantially greater incremental recovery of oil in comparison with the case of using binary surfactant-polymer combination alone. The mechanisms contributing to EOR with nanofluids, such as IFT reduction and wettability alteration, were explored. Incorporating NPs at concentrations of 0.1, 0.2, and 0.4 wt% led to incremental oil recoveries of 4.01 %, 12.35 %, and 12.73 % of the original oil in place (OOIP), respectively, as opposed to the recovery achieved using only SDS + TX-100 + XG. Consequently, these findings advance the understanding of the potential application of SiO2 NPs in combination with the binary surfactant-polymer mixture as effective chemical EOR agents. Additionally, these insights aid in identifying suitable sandstone reservoirs for nanofluid application, contributing to the optimization of oil recovery strategies.

Study of Heavy Oil In-situ Combustion with Copper Biocatalysts: Kinetics and Thermodynamic Aspects of High-Temperature Oxidation Reactions

In-situ combustion is considered an efficient thermally enhanced oil recovery method. However, the combustion front stabilization remains a challenge for the scientific community. The present study examines the efficacy of copper tall oil (Cu-TO) and copper sunflower oil (Cu-SFO) on heavy oil high-temperature oxidation reactions, which are believed to solve this challenge. We applied non-isothermal differential scanning calorimetry (DSC) analyses combined with an isoconversional kinetic approach in order to calculate kinetic parameters, thermodynamic functions, and the effective rate constant of these reactions. The obtained results demonstrated that both catalysts are able to reduce the activation energies and shift oxidation regions to lower temperatures, with Cu-SFO showing superior performance. Kinetic predictions further supported these findings and revealed that the selected catalysts contributed significantly to decreasing oxidation times across all conversion ranges. Additionally, thermodynamic analyses indicated that Cu-SFO facilitated a more ordered and energetically favorable oxidation process, as demonstrated by increasingly negative entropy values and consistently lower Gibbs free energy. The research highlights the Cu-SFO catalyst exceptional ability to accelerate the transition from low-temperature to high-temperature oxidation while maintaining high catalytic activity. Taken together all these results, this research work contributes to provide comprehensive insights from the kinetic and thermodynamic analysis that reveal unique catalytic effects and reaction mechanisms, presenting an approach to stabilize combustion front and improve heavy oil recovery efficiency, addressing a critical challenge in the field of in-situ combustion.

Efficiency analysis of the application of thermal methods at the Pirallahi and Darwin bank fields

The efficiency of oil and gas field development is associated with the correct choice of appropriate measures to be implemented. This research considers the Pirallahi and Darwin Bank fields with hard-to-recover oil reserves. The Pirallahi field is located in the eastern part of the Absheron Peninsula. The initial balance reserve for the facility is 4 million tons, and the level of reserve utilization is 19%. Among the notable features, the Pirallahi deposit represents the southern fold of the PK (Pre-Kirma- ki) horizon. Across the horizon, the initial balance reserve is approximately one million tons, and the utilization rate is 17%. In other groups, the level of utilization exceeds 20%. Accordingly, the volume of initial balance reserves ranges between 8-35 million tons. Industrially important objects here are KSv (Kirmaki suite, fifth horizon), KSn (Kirmaki suite, n horizon), and PKS (Post-Kirmaki suite). To develop oil reserves, more than 1000 production wells were drilled at different stages of the development process. The southern fold consists of a brachyanticline extending from northwest to southeast. The main tectonic element of the southern fold is its thrust nature and its very complex tectonic structure. The fold is heavily watered. Therefore, to increase the efficiency of developing these fields, it is necessary to use appropriate methods of influencing the formations. To enhance the efficiency of the development process in the northern part, the in-situ combustion method was applied. The Darwin Bank field belongs to the Absheron archipelago and has a tectonic brachyanticlinal structure. The structure is complicated by numerous longitudinal and transverse faults. It is divided into six tectonic zones by several transverse and one longitudinal fault passing through the crest. Darwin Bank oils are heavy oils with low sulfur content. In addition, low paraffin and high resin content are observed in the composition of field oil. For both fields, the recovery rate of geological reserves fluctuates around 30%. The article, primarily, examines the selection of objects and the use of enhanced oil recovery methods in these fields. The in-situ combustion method was used in the northern part of the Pirallahi field and Darwin Bank.

Influence of Polymer Concentration on the Viscous and (Linear and Non-Linear) Viscoelastic Properties of Hydrolyzed Polyacrylamide Systems in Bulk Shear Field and Porous Media.

Enhanced oil recovery (EOR) methods are generally employed in depleted reservoirs to increase the recovery factor beyond that of water flooding. Polymer flooding is one of the major EOR methods. EOR polymer solutions (especially the synthetic ones characterized by flexible chains) that flow through porous media are not only subjected to shearing forces but also extensional deformation, and therefore, they exhibit not only Newtonian and shear thinning behavior but also shear thickening behavior at a certain porous media shear rate/velocity. Shear rheometry has been widely used to characterize the rheological properties of EOR polymer systems. This paper aims to investigate the effect of the polymers' concentrations, ranging from 25 ppm to 2500 ppm, on the viscous, linear, and non-linear viscoelastic properties of hydrolyzed polyacrylamide (HPAM) in shear field and porous media. The results observed indicate that viscous properties such as Newtonian viscosity increase monotonically with the increase in concentration in both fields. However, linear viscoelastic properties, such as shear characteristic time, were absent for concentrations not critical in both shear rheometry and porous media. Beyond the critical association concentration (CAC), the modified shear thinning index decreases in terms of concentration in both fields, signifying their intensified thinning. At those concentrations higher than CAC, the viscoelastic onset rate remains constant in both fields. In both fields, the shear thickening index, a strict non-linear viscoelastic property, initially increases with concentration and then decreases with concentration, signifying that the polymer chains do not stretch significantly at higher concentrations. Also, another general observation is that the rheological properties of the polymer solutions in both porous media and shear rheometry only follow a similar trend if the concentration is higher than the CAC. At concentrations less than the CAC, the shear and porous media onset rates follow different trends, possibly due to the higher inertial effect in the rheometer.

Optimization Analysis of In-Situ Conversion and Displacement in Continental Shale Reservoirs.

In the context of growing global energy demands and the need for efficient extraction techniques, this research, based on numerical analysis, addresses the high-energy demands of in situ conversion by introducing a two-stage development strategy. The strategy begins with an initial continuous heating stage, followed by a thermal stabilization stage. It culminates in a hydrocarbon production stage, which is divided into primary recovery and water injection-enhanced recovery. The findings demonstrate that the reservoir temperature continues to increase even after the stop of heating. Consequently, the reactions within the reservoir persist, leading to increased hydrocarbon generation. The heating stage also helps restore reservoir pressure, enabling high production rates of hydrocarbons during the first year of primary recovery. However, natural depletion subsequently occurs, requiring an enhanced oil recovery (EOR) method. While water injection is a viable EOR method, it proves less effective due to high water breakthroughs in the producer well. Additionally, a comprehensive analysis reveals that hydrocarbon generation and production are closely related to the calibration of energy input and the duration of injection. These results underscore the critical importance of precise energy management and injection timing in optimizing hydrocarbon recovery. By enhancing our understanding of the thermal dynamics and reaction kinetics within the reservoir, this research contributes to the development of more efficient and sustainable extraction technologies, ultimately improving the feasibility of commercial shale oil production.

Pore-scale fluid distribution and remaining oil during tertiary low-salinity waterflooding in a carbonate

The utilization of low-salinity waterflooding as a promising enhanced oil recovery method has exhibited exciting results in various experiments conducted at different scales. For carbonate rock, pore-scale understanding of the fluid distribution and remaining oil after low-salinity waterflooding is essential, especially the geometry and topology analysis of oil clusters. We performed the tertiary low-salinity waterflooding and employed X-ray micro-CT to probe the pore-scale displacement mechanism, fluid configuration, oil recovery, and remaining oil distribution. We found that the core becomes less oil-wet after low-salinity waterflooding. Furthermore, we analyzed the oil-rock and oil-brine interfacial areas to further support the wettability alteration. By comparing images after high-salinity waterflooding and low-salinity waterflooding, it is proven that wettability alteration has a significant impact on the behavior of the two-phase flow. Our research demonstrates that low-salinity waterflooding is an effective tertiary enhanced oil recovery technology in carbonate, which changes the wettability of rock and results in less film and singlet oil.

Numerical pore-scale investigation of two-phase displacement with non-Newtonian defending fluid

In the petroleum engineering and chemical industries, fluids engaging in displacement often have non-Newtonian properties, even though many former studies assume constant viscosities in the defending fluid. In this study, the computational fluid dynamics approach was performed in a two-dimensional model with uniformly distributed disks. This arrangement helps reveal the phenomenon and mechanics of how non-Newtonian characteristics of defending fluid affect two-phase displacement in porous media. Both global (in the whole medium) and regional (in the pore throat) studies revealed that shear-thinning makes capillary force and the pressure in the invading fluid decisive and leads to a uniform pattern. Meanwhile, the shear-thickening causes fingering due to the pressure drop in the defending fluid that becomes decisive. Cases of increasing injection rates were investigated to verify their ability to improve efficiency. The results verified that increased injection rates are effective in shear-thinning cases but energy-intensive when it comes to costs in shear-thickening cases. Finally, the viscosity ratio and capillary number (M-Ca) diagram were extended by plotting non-Newtonian cases as lines to consider viscosity variation. An estimation method was presented, which calculates the characteristic viscosity and locates non-Newtonian cases on an M-Ca diagram. This work can serve as a reference for enhanced oil recovery method development and microfluidic manipulation.

3-D Modelling and Simulation of a Reservoir for Surfactant-Polymer Flooding Using Eclipse Software

Surfactant-polymer flooding is a tertiary enhanced oil recovery method used to recover oil that remained in the reservoir after the primary and secondary oil recovery mechanisms. Predicting the pressure in the reservoir is important for oil production as pressure changes with time. A suitable approach to achieve this task is to derive fluid flow equation based on the reservoir characteristics and solve them numerically which provide the solution to the mathematical fluid flow model (diffusivity equation). In this study, 3-D reservoir was modelled using Eclipse software. The fluid flow equations in a porous media were derived based on the simulated model and the reservoir conditions. Numerical solution using implicit formulation to solve the mathematical fluid flow model (diffusivity equation) was investigated by developing Python codes using Jupyter library to ascertain the pressure distribution for the reservoir and imported into Eclipse simulator. Simulation was carried out using surfactant-polymer and reservoir properties to determine the oil recovery. The results of the study showed that pressure increases with time as oil production continued, and water saturation decreased for the grid-cells of the reservoir. Waterflooding had oil recovery of 38.0% and water-cut of 59.0%, while surfactant flooding had oil recoveries of 42.0%, 46.5%, 49.0% and water-cut of 57.0%, 51.0%, 46.3%. In addition, polymer flooding had oil recoveries of 44.3%, 48.4%, 54.0% and water-cut of 50.0%, 45.0% and 33.0% respectively at different concentrations of 0.3%wt. 0.4%wt. and 0.5%wt.

Microcapsule preparation process research and current status of oilfield application

AbstractTraditional tertiary oil recovery methods are fraught with challenges such as significant reagent adsorption, voluminous injection requirements, limited sweep efficiency, and inadequate intelligent targeting. These issues lead to suboptimal displacement of residual oil, resulting in the inability to mobilize substantial crude oil resources and thus yielding low recovery rates. Microcapsules—spherical particles with micron or nanometer scale diameters—have been extensively utilized across various sectors, including food storage, targeted drug encapsulation, and fragrance containment, owing to their distinct advantages in controlled release, isolation, and targeted delivery. These applications have successfully achieved industrialization and commercialization. In recent years, numerous researchers have explored the application of microcapsule preparation processes to diverse facets of oil extraction, with the aim of further enhancing oil recovery (EOR). This article elucidates the mechanism of action of microcapsules, their preparation methods (encompassing in situ polymerization, interfacial polymerization, spray drying, solvent evaporation, phase separation, and supercritical CO2‐assisted techniques), characterization and evaluation methodologies, among other aspects. It encapsulates the current status and principal challenges associated with the application of microcapsule preparation processes in oilfield development and probes the potential and pivotal research directions for their oilfield applications.

Experimental study on the mechanism of associated gas generation by heavy oil aquathermolysis and thermal cracking during steam injection

Previously, we proposed an innovative method for heavy oil recovery known as the ISSG-SAGD (in-situ solvent generation enhanced steam assisted gravity drainage) technique. This technology can improve heavy oil recovery efficiency, reduce steam consumption, and mitigate acid gas emissions. However, the reaction kinetic model used in numerical simulation was derived from literature reports and reasonable assumptions, lacking experimental validation. This study addresses this gap by conducting a series of experiments to investigate the mechanism of associated gas generation under steam injection conditions. We differentiated the reaction temperature window of aquathermolysis and thermal cracking based on the quantity and composition of the associated gas generated. The study revealed that aquathermolysis, occurring at 240–280℃, produces a small amount of associated gas (gasification degree of 0.32 %), predominantly CO2 (about 68 %). In contrast, thermal cracking, occurring at temperatures up to 380℃, significantly increases gas generation (gasification degree of 14.33 %), with light hydrocarbons (C1–5) constituting about 80 % of the gas produced. The reaction rate was found to be proportional to the reaction temperature and time. The SARA analysis showed that saturates and aromatics content increased, while resins and asphaltenes decreased after both reactions. A kinetic model for associated gas generation was established, and kinetic parameters such as activation energies and frequency factors were derived using the Arrhenius method. For example, the activation energy for CO2 generation increased from 18.19 kJ/mol during aquathermolysis to 147.58 kJ/mol during thermal cracking. This study provides a comprehensive understanding of the associated gas generation mechanisms and characteristics under steam injection, supporting the feasibility and potential application of the ISSG-SAGD technique in heavy oil recovery.

Research on Inter-Fracture Gas Flooding for Horizontal Wells in Changqing Yuan 284 Tight Oil Reservoir

In tight reservoir development, traditional enhanced oil recovery (EOR) methods are incapable of effectively improving oil recovery in tight reservoirs. Given this, inter-fracture flooding is proposed as a new EOR method, and physical model simulation and numerical simulation are performed for inter-fracture water flooding. Compared with inter-fracture water flooding, inter-fracture gas flooding has a higher application prospect. However, few studies on inter-fracture gas flooding have been reported, and its EOR mechanisms and performance are unclear. This paper used the geological model of the actual tight reservoir to carry out numerical simulations for two horizontal wells in the Changqing Yuan 284 block. The results showed that (1) inter-fracture gas flooding can effectively supplement formation energy and increase formation pressure; (2) inter-fracture gas flooding delivers simultaneous displacement, which can effectively increase the swept area in tight reservoirs; (3) injected CO2 dissolves into the reservoir fluid, reduces fluid viscosity, and improves fluid flow through the reservoir; and (4) the recovery factor increment of the CO2 injection is higher than those of natural gas injection and N2 injection. The findings of this research provide references for the production and development of tight reservoirs.

Research progress and potential of new enhanced oil recovery methods in oilfield development

This paper reviews the basic research means for oilfield development and also the researches and tests of enhanced oil recovery (EOR) methods for mature oilfields and continental shale oil development, analyzes the problems of EOR methods, and proposes the relevant research prospects. The basic research means for oilfield development include in-situ acquisition of formation rock/fluid samples and non-destructive testing. The EOR methods for conventional and shale oil development are classified as improved water flooding (e.g. nano-water flooding), chemical flooding (e.g. low-concentration middle-phase micro-emulsion flooding), gas flooding (e.g. micro/nano bubble flooding), thermal recovery (e.g. air injection thermal-aided miscible flooding), and multi-cluster uniform fracturing/water-free fracturing, which are discussed in this paper for their mechanisms, approaches, and key technique researches and field tests. These methods have been studied with remarkable progress, and some achieved ideal results in field tests. Nonetheless, some problems still exist, such as inadequate research on mechanisms, imperfect matching technologies, and incomplete industrial chains. It is proposed to further strengthen the basic researches and expand the field tests, thereby driving the formation, promotion and application of new technologies.

Assessing the impact of geochemical mechanism and interpolation factor selection on the precision of low-salinity waterflooding modelling: a comparative study

ABSTRACT The efficacy of low salinity waterflooding (LSWF) as an enhanced oil recovery (EOR) method in carbonate formations has been well established; however, its geochemical modelling in such reservoirs remains insufficiently explored. This study aims to bridge this gap by conducting a comparative analysis of three well-recognised geochemical mechanisms including fines migration, rock dissolution/precipitation, and multi-ion exchange (MIE). Our research encompasses two parts: experimental and modelling. First, we conducted four coreflooding experiments to study the effect of LSWF on oil recovery in core scale as well as on rock wettability by measuring the contact angle of the crude oil-brine-rock system. In the next step, we created a one-dimensional compositional model in CMG-GEMTM for LSWF, validated it using the obtained experimental results, and compared the accuracy of the three geochemical mechanisms one-by-one. The results of the experimental section, confirm the positive effect of LSWF on oil recovery: 34.3% with seawater (40,000 ppm), 42.5% with LoSal-01 (10,000 ppm), 49.7% with LoSal-02 (5,000 ppm), and 60.9% with LoSal-03 (2,000 ppm). The experiments also show the wettability alteration through the reduction in the contact angle. Furthermore, the modelling results reveal that choosing MIE as the governing mechanism and sulphate concentration ([ S O 4 2 − ]) as the relevant interpolation factor (IF) leads to the most accurate LSWF model. After identifying the most accurate mechanism, we detected the wettability alteration in the model by showing the movement of oil and water relative permeability curves intersection point on the Kr-Sw diagram toward the right side.