Slug Size Research Articles

Adaptability and enhanced oil recovery performance of surfactant–polymer flooding in inverted seven-spot well pattern

As one of the leading technologies for chemical enhanced oil recovery (cEOR), surfactant–polymer (SP) flooding technology has long attracted the interest of petroleum scientists and engineers. However, most of its application scenarios are based on the five-spot well pattern. The EOR potential in an inverted seven-spot well pattern is seldom ever recorded. The applicability of the SP system in the inverted seven-spot well pattern was examined based on the physical characteristics of Karamay Oilfield in China. The numerical simulation and the one-dimensional core flooding experiment were used to compare the sweep intensities and EOR abilities of the two well patterns. The migration law and the EOR ability of the SP system were assessed by a specially made one-third inverted seven-spot configuration. The main controlling factors and compatibility charts of SP flooding development in the inverted seven-spot well pattern were obtained. Results show that 61% of the region is represented by a weak swept state in the inverted seven-spot well pattern. The effective swept area is greatly increased by appropriately raising the viscosity and slug size of the SP system. Compared to constant viscosity injection, step-down viscosity injection further increases the sweep range and oil recovery. The inverted seven-spot well pattern has a greater swept area of the SP system than the five-spot one, but a weaker strength. Polymer concentration is the most effective factor of SP flooding in the inverted seven-spot well pattern, followed by oil viscosity and surfactant concentration. The study can broaden the application of the SP system in the inverted seven-spot well pattern.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

WAG injection in porous media: A microfluidic analysis

Water Alternating Gas (WAG) injection is one of the common methods to displace oil in porous media, which is relevant to many applications including soil remediation or enhanced oil recovery from underground reservoirs. We conducted a comprehensive series of experiments to extend the fundamental understanding of WAG injection in porous media. Three types of porous media were manufactured with a 3D printer in this investigation. The first medium had single permeability (S), the second one was fractured (F), and the third one was a medium with dual permeability (D). The porous media were saturated with silicone oil. Nitrogen and water were used to displace oil under different WAG ratios of 4:1, 2:1, 1:1, 1:2, and 1:4. High-resolution imaging was used to quantify displacement dynamics. The highest oil recovery was observed under WAG ratio of 1:1, i.e., the equal slug size of the water and gas. The obtained results showed that the WAG ratio of 1:1 injection in the S medium recovered 55% of the oil, while in the F and D medium, the recovery efficiency was 36% and 47%, respectively. Our findings offer new insights regarding effects of heterogeneity on WAG injection efficiency in porous media under different boundary conditions.

Investigation on immiscible N2 WAG and SWAG after water flooding in the paleo-subterranean river of fractured-vuggy reservoirs

The complex spatial distribution of caves and fractures results in the low oil recovery after water flooding in paleo-subterranean river of fractured-vuggy reservoirs. This paper tries to solve the problem of how to adopt water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) to enhance oil recovery in paleo-subterranean river reservoirs. Aiming at this objective, we constructed one physical experimental and numerical model according to the geological section in Tahe Oilfield. The research on water flooding, WAG, and SWAG were carried out through experiments and simulations. The results show that there were four kinds of remaining oil after water flooding in the paleo-subterranean river karst reservoirs, i.e., blind end remaining oil, shielded remaining oil, attic remaining oil, and corner remaining oil. WAG can extract the shielded remaining oil, attic remaining oil, and part of the corner remaining oil efficiently, while SWAG can only work on the attic remaining oil. In addition, too low injection rate lacked driving force support and restricted the expansion of the swept zone. Too small gas-water ratio and slug size can’t play a good role in gas displacement. This paper is the first systematic study of the paleo-subterranean river reservoirs, and the results can provide a basis for production practice.

Surfactant formulation development for shallow reservoirs with high clay content

Sandstone reservoirs with high clay content can potentially adsorb large amounts of surfactants making the chemical flood processes unattractive. The objective of this work was to develop an alkaline-surfactant-polymer (ASP) process for a shallow, clayey sandstone reservoir to minimize surfactant retention. The phase behavior study was conducted to identify commercially available surfactants that display ultralow interfacial tension behavior. The selected surfactant formulations were tested in tertiary ASP core floods in outcrop and reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for core floods. The cumulative oil recovery was in the range of 92–96% of the original oil in place (OOIP) in the core floods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content due to the use of alkali. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. Injection of the ASP slug immediately after the field brine flood with divalent ions did not cause any plugging or adverse effect. The novelty of this work lies in designing ASP formulations with a single surfactant and reducing the residual oil saturations to ∼3% in field cores along with low surfactant retention. This paper illustrates a workflow to identify the chemical formulation, chemical concentrations and slug sizes.

Optimization Study of Polymer-Surfactant Binary Flooding Parameters in Maling Jurassic Low Permeability Reservoir

The low-permeability Jurassic reservoir in Changqing Maling has been in the middle and high water cut stage after long-term development of water injection. In order to improve development efficiency and further explore a new way to enhance oil recovery of the reservoir, a significant development test and a polymer-surfactant flooding study were carried out in the Maling Beisan area in 2011. Compared with other polymer-surfactant flooding reservoir of PetroChina, Jurassic reservoir in Beisan area had relatively low permeability and high salinity of formation water and injected water, which puts forward higher requirements on the injectivity and salt resistance of the binary system. At the same time, the viscosity of the formation crude oil was low, and the viscosity of the polymer required to achieve the optimum fluidity ratio was relatively low, which is an important advantage of implementing the binary flooding in the reservoir. In this paper, hydrophobic associating polymer and betaine surfactant were selected through laboratory experiments. According to the experimental data, numerical simulation technology was used to analyze and optimize the influence factors, including injection speed, injection-production ratio, slug size, slug polymer, and surfactant concentration. Finally, the development index of binary flooding was predicted. The results show that the optimized polymer-surface system had good injectivity and high formation compatibility. Through on-site differential control measurement of injection and production, the recovery was enhanced significantly. This study had guiding significance for the production of polymer-surface flooding in the similar reservoirs.

Experiments of Gas-water Cooperative Flooding in Fracture Network System

Fractures are the main seepage channels and the critical oil storage space in fracture-vuggy reservoirs. In this paper, the staggered fracture system was abstracted into an orthogonal fracture network. A physical experimental model was made with a laser-etched acrylic plate. The physical experiments of water flooding, gas flooding, water-alternating-gas, and simultaneous-water-and-gas were carried out using the physical experiment model of the fracture network. The results show that gas is more accessible to break through in gas flooding than water in water flooding, resulting in a lower recovery factor. Water-alternating-gas and simultaneous-water-and-gas can effectively improve oil displacement efficiency through the action of gravity difference and the interaction mechanism of gas and water. Increasing the injection rate properly, increasing slug size properly before water and gas breakthrough during water-alternating-gas simultaneous-water-and-gas, and decreasing the gas-water ratio properly during simultaneous-water-and-gas simultaneous-water-and-gas can effectively expand the sweep scope and improve recovery. The experiment provides a basis for efficient water and gas injection development in fracture-vuggy reservoirs.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

Experimental investigation of carbon dioxide flooding in heavy oil reservoirs for enhanced oil recovery

With the attention paid to greenhouse gas emission reduction all over the world, CO2 capture, utilization and storage technology has developed rapidly. Predecessors have done a lot of work on the effect of CO2 on properties of the oil, the changes of parameters after CO2 injection are different. Through PVT, slim tube test and phase state simulation, this work studied the influence law of CO2 injection on the properties of heavy oil in offshore reservoirs in eastern China. It defines the adaptability and oil displacement mechanism of CO2 flooding in the reservoirs. In this work, 12 oil displacement experiments were carried out to quantify the effect of injection sequence, slug size, gas injection rate, and soaking time on oil recovery in the hydrogen carbon reservoir. These experimental results have indicated the influence of different factors on oil displacement effect. It provides strong evidence for the efficient development and enhanced oil recovery of the oilfield. The results indicate that the gas–water alternative injection is better than continuous water flooding or continuous CO2 flooding by improving the ultimate recovery at 8.9% and 12.7% respectively. A larger CO2 slug is beneficial to improve the ultimate oil recovery and the injection rate of CO2 slightly affects the ultimate oil recovery factor. Longer soaking time can improve the ultimate recovery either. The ultimate recovery increases rapidly with the soaking time when it less than 24 h, but the ultimate oil recovery hardly increases when the soaking time is longer than 24 h.

Heat transfer analysis of immiscible slug flow-based microchannels: Study of channels with extended surfaces

Immiscible injection of slug(s) into a microchannel with square blocks attached to the bottom surface of the channel is studied using the phase-field approach for interface tracking. It is confirmed that immiscible injection enhances heat transfer by up to 85% compared to miscible injection considering identical thermophysical properties. The differences in the rate of heat removal between immiscible and miscible injection are explained by the hydrodynamics of the system. It is also found that larger injected slug size does not necessarily result in greater heat removal and causes the average Nusselt number to behave non-monotonically, reaching an optimum value at a specific slug length. This non-monotonic trend has been explained by analyzing the hydrodynamics of the system. The effect of the inter-block distance generally showed a monotonic increasing trend for the average Nusselt number, except for a single slug length. This behavior has been explained by the vorticity and Fourier transform analysis. An alternating slug injection configuration has also been analyzed. The analysis of this configuration reveals a non-monotonic behavior of the average Nusselt number vs the number of injected slugs. This non-monotonic behavior shows that for each value of the selected slug length, there is a critical number of slugs, and consequently, a critical slug length for which the average Nusselt number reaches a maximum. The hydrodynamics of the system justifies this non-monotonic behavior. Finally, the friction factor and performance evaluation criterion are presented as a guideline for the design of the microchannels based on flow configuration.

Effect of viscosity and heterogeneity on dispersion in porous media during miscible flooding processes

In this paper, a mathematical model has been developed to quantitatively examine the effect of viscosity and heterogeneity on dispersion in porous media at the pore scale during miscible flooding processes. More specifically, the Navier-Stokes equation and advection-diffusion equation are coupled with supplementary equations to describe the solvent transport behaviour. Two-dimensional heterogeneous models are numerically developed as a function of porosity and permeability, assuming that the grain sizes satisfy normal distribution. In addition, the performance of miscible hydrocarbon gas injection in heterogeneous porous media is comprehensively evaluated. It is found that a larger aspect ratio (ratio of pore throat size) in the single non-flowing pore model results in a greater asymmetry of the concentration curve. As for single non-flowing pore models and heterogeneous models, the dispersion coefficients increase with the expansion of the non-flowing domain. Both the heterogeneity of porous media and the variable viscosity of th fluid mixture contribute to the asymmetry of the concentration curve in the heterogeneous model. A negative correlation is established between the sorting coefficients of pore throat size and the power-law coefficients. As for slug injection, the injected solvent slug size along the longitudinal direction does not effectively influence the longitudinal length of the mixing zone for a given porous medium and fluids, though the Peclet number and the porosity greatly affect the length and concentration distribution of the mixing zone. Cited as: Bai, Z., Song, K., Fu, H., Shi, Y., Liu, Y., Chen, Z. Effect of viscosity and heterogeneity on dispersion in porous media during miscible flooding processes. Advances in Geo-Energy Research, 2022, 6(6): 460-471. https://doi.org/10.46690/ager.2022.06.03

Theoretical Research in Laboratory and Field Trial of Micro-Nano-Oil Displacement System Conformance Control Technology

Abstract In recent years, a series of field tests of a new micro-nano-oil displacement system (MNS) conformance control technology have been carried out in different oilfields, which can increase oil production and reduce water cut obviously. However, compared with its field application, the research on its performance evaluation and oil displacement mechanism is still in the initial stage. And it is urgent to carry out relevant research work. Therefore, this paper made a profound study on its physicochemical properties, reservoir adaptability, transport and deep fluid diversion ability, and oil displacement mechanism. Results show that MNS with a series of particle sizes in different sizes (from nanometer to micrometer) can be obtained. And it has good expansion ability. Through reservoir adaptability evaluation, the matching relationship between the size distributions of MNS particles and pore throat is given, which has important guiding significance for MNS particle size selection for target reservoir before field trial. Furthermore, MNS has strong transport ability. When migrating in the porous media, it shows the motion feature of “trapping, deformation, migration, retrapping, redeformation, and remigration,” which can obtain better oil incremental effect than traditional polymer flooding. Under the condition of the same agent type, composition, and slug size, the oil recovery rate can be further enhanced by 6.96%. In addition, MNS conformance control technology has obtained good technical and economic effect in the 8 oilfields, with the lowest input-output ratio of 1.67 and the highest of 14.37. The reason why MNS have the above-mentioned good performances depends on its advanced mechanism: the unique particle phase separation phenomenon. When transporting in porous media, MNS particles gather in the larger pore to form bridge blocking, and its carrier fluid displaces oil in the small pore. Working in cooperation, MNS can realize deep fluid diversion and expand macroscopic and microscopic swept volume.

Experimental Study on Enhancing Heavy Oil Recovery by Multimedia-Assisted Steam Flooding Process

Aiming to reduce the negative effect of steam channeling in the late stage of steam flooding applied in heavy oil reservoirs, experimental studies were carried out on selective plugging of solid particles, added to single-medium- and multimedia-assisted steam flooding. This work also explored the mechanisms of enhancing heavy oil recovery by applying plugging agent- and multimedia-assisted steam flooding and its optimized injection parameters. Through solid particle plugging experiments, this study clarifies the high-efficiency solid particle plugging mechanism, with an optimized slug size of 0.40 PV and plugging ratio of over 98%. Through single-medium- and multimedia-assisted steam flooding experiments, this study confirms that gas-assisted steam flooding has an effect of synergistic oil displacement and that a CO2 with urea solution-assisted steam flooding method achieves the best production performance. Its oil recovery factor is 10.7% higher than that of the steam flooding process. Parallel sand pack models with a permeability difference of more than 10 times were used to mimic a heavy oil reservoir with high-permeability channels, and the selective plugging of solid particles was carried out. The plugging ratio of high-permeability formation reached 91.20%, playing an effective plugging role. Solid particle plugging is less effective to the low-permeability formation, with the plugging ratio at only 32.39%. Based on the selective plugging of solid particles, a plugging agent- and multimedia-assisted steam flooding experiment was conducted, the high-permeability formation was effectively plugged, and the swept volume of the low-permeability formation increased significantly. The final recovery factor of the high-permeability formation was enhanced by 11%, and the recovery factor of the low-permeability formation increased by 3 times, reaching 36.38%. Therefore, solid particle plugging effectively alleviates the impact of high-permeability formation caused by permeability difference during steam flooding.

Study of the Surfactant Transport Law Based on an Improved Adsorption Model with an Artificial Seismic Wave

To explore the law and mechanism of enhanced surfactant flooding with a low-frequency artificial seismic wave, for single-phase fluids in porous media, a heterogeneous two-stage adsorption model for a surfactant with a low-frequency artificial seismic wave is introduced into the surfactant transport equation of a single-phase fluid. With this model, the surfactant fluid transport model in porous media with an artificial seismic wave is obtained. The model is solved using the C-N difference and chasing method. The migration law of the surfactant is simulated and quantitatively analyzed for different vibration accelerations, injection slug sizes, displacement speeds, and reservoir parameters with the action of low-frequency artificial seismic waves. The results show that artificial seismic waves can increase the effective range of the surfactants and reduce the number of chemical agents through reduced adsorption. Low-frequency vibration with the same surfactant injection rate can increase the effective range by a factor greater than one. For the same effective action distance, the dose of chemical agents can be reduced by more than 60%, and the optimal acceleration and the injection slug size are 0.3 m/s2 and 0.4 PV, respectively. With the increase of the injection rate, the effect of low-frequency vibration on the diffusion and transport of the surfactant decreases. A low-frequency wave combined surfactant has a better effect on the low permeability reservoirs. The research results provide important support for further understanding of the low-frequency artificial seismic wave composite surfactant flooding law and the optimization of the field parameters.

Predicting the surfactant-polymer flooding performance in chemical enhanced oil recovery: Cascade neural network and gradient boosting decision tree

Surfactant-polymer flooding is one of the most important enhanced oil recovery (EOR) techniques, which refers to the injection of surfactant slugs and polymer drives. Two crucial decision-making parameters in EOR operations are net present value (NPV) and oil recovery factor (RF). Herein, various intelligent models, based on multilayer perceptron (MLP), cascade neural network (CNN), radial basis function (RBF), neural networks as well as support vector regression (SVR), and decision tree (DT) algorithms are proposed toward estimating these two parameters with respect to polymer drive size, surfactant slug size, the salinity of polymer drive, Kv/Kh ratio, surfactant concentration, and polymer concentration in polymer drive and surfactant slug. The results exhibited the outperformance of the CNN model trained with the Levenberg Marquardt algorithm in forecasting the RF and NPV with average absolute errors of 0.66% and 1.95%, respectively. Moreover, the results of the sensitivity analysis reflected that the most effective inputs on the predicted value of RF were surfactant concentration and surfactant slug size, while surfactant concentration and polymer concentration in surfactant slug could considerably affect the NPV model’s output. Lastly, the outlier detection analysis revealed that the employed data is valid and only two points were detected as outliers.

Performance Evaluation of Ionic Liquids Using Numerical Simulation

Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery optimization, has taken a prominent role in resource management. Chemical flooding has proved to be one of the most efficient EOR techniques. This study investigated the potential of employing Ionic Liquids (ILs) as alternative chemical agents for improving oil recovery. There is very little attention paid to employing this technique as well as few experimental and simulation studies. Consequently, very limited data are available. Since pilot and field studies are relatively expensive and time consuming, a numerical simulation study using CMG-STARS simulator was utilized to explore the efficiency of employing 1-Ethyl-3-Methyl-Imidazolium Acetate ([EMIM][Ac]) and 1-Benzyl-3-meth- limidazolium chloride ([BenzMIM][Cl]) with respect to improving medium oil recovery. Eight different lab-scale sandpack flooding experiments were selected to develop a numerical model to obtain the history matching of the experimental flooding results using CMG-CMOST. We observed that the main challenge was tuning the relative permeability curves to achieve a successful match for the oil recovery factor. Finally, a sensitivity study was performed to examine the effect of the chemical injection rate, the chemical concentration, the slug size, and the initiation time on oil recovery. The results showed a noticeable increase in the oil RF when injecting IL compared to conventional waterflooding.

A comparative investigation of flow structures in three-dimensional supercritical water and gas-solid fluidized bed via two-fluid model simulations

A comparative study of flow characteristics in three-dimensional supercritical water fluidized beds (SCWFB, 440–560 ℃, 22–26 MPa), cold gas-solid fluidized beds (CGSFB, 20 ℃, 0.1 MPa), and high-pressure and high-temperature gas-solid fluidized beds (HGSFB, 440–560 ℃, 22–26 MPa) was conducted via two-fluid model simulations across different fluid velocities, un-fluidized bed heights, pressures and temperatures. Bubble (or slug) and particle dynamics, fluid velocities, and bed expansions are investigated. The results show that, the drag forces of particulate phase are around 0.4 times particulate phase weights in SCWFB. Compared with CGSFB, SCWFB has lower minimum fluidization velocities, smaller bubble and slug sizes, more bubble and slug numbers, higher bed expansions and slug onset heights, and more uniform gas-solid interactions. Flow structures in SCWFB are similar to those in HGSFB. Pressure and temperature have less effects on the flow structures than fluid velocity and un-fluidized bed height in both SCWFB and HGSFB.

Hydrodynamic study of internal circulation inside microreactor for transesterification process

Microreactors are important devices used in the field of process intensification. The use of microreactors offers several advantages, such as larger surface area to volume ratio, increasing mass and heat transfer rates, easy control of reagents and reactions, as well as easy scalability. The hydrodynamics within the microreactor produce several flow patterns, such as annular, parallel, and slug flow. Slug flow is of particular interest as it allows for greater mass transfer as mass transfer occurs not only at the interface but also within the internal circulations of the slug. The aim of this research was to investigate the formation of these internal circulations of these slugs under different parameters and how these internal circulations affect the mass transfer of the process. An inverted microscope was used to visualize the flow patterns of the internal circulation with the help of dye or small particles. The slug shape remains relatively unchanged at different catalyst concentrations, flowrates and oil-to-methanol ratios, and the internal circulations formed in the slugs remain fully formed regardless of the slug size. It can be said that process intensification of transesterification utilizing microreactor is a viable option and can be further improved with optimal parameters.

Impact of proper design of operating parameters on the performance of CO2-Water Alternating Gas (CO2-WAG) injection: a simulation study

Water-alternating-gas (WAG) is one of the enhanced oil recovery (EOR) methods in which both water and gas are injected into the reservoir. Among different WAG processes, CO2-WAG is one the most environmental-friendly and efficient methods. The low minimum miscibility pressure (MMP) of CO2 turns this gas to a special candidate for EOR applications. In this study, impact of anisotropy coefficient and operating parameters including injection rate, pattern size and slug size on performance of this process was investigated through 360 different cases of numerical simulation. Also, a modification to the currently used dimensionless aspect ratio was proposed to enhance the accuracy of predicting oil recovery factor during WAG process. Generally, it was concluded that regardless of anisotropy coefficient, oil recovery factor increases as the ratio of well distance to reservoir thickness increases. For instance, for anisotropy coefficient of 0.1, the average recovery factor for well distance to reservoir thickness of 10 and 100 was 68% and 74%, respectively. In addition, it was concluded that the performance of WAG process is logarithmically correlated with anisotropy coefficient and well distance to reservoir thickness. Finally, it was concluded that the proposed modification for the dimensionless aspect ratio considerably increases its accuracy.

Water alternating gas (WAG) recovery process evaluation through simulation for a giant middle-eastern carbonate reservoir

The objectives of this article it to present a water alternating gas (WAG) process evaluation methodology for a giant middle eastern carbonate reservoir. The methodology involves enhanced oil recovery through an immiscible hydrocarbon water alternating gas (WAG) injection method. Although water alternating gas injection is a proven enhance oil recovery technique and has been around for some time now, only a limited published literature is available on complete evaluation of immiscible WAG process in field application. This article aims to bridge the gap by presenting a detailed study of immiscible water alternating gas evaluation process. In this article a complete methodology for evaluating a water alternating gas injection recovery technique is presented. It includes optimization of WAG cycle length, WAG ratio, production constraints, injected gas compositions, WAG duration, and WAG slug size. The work presented in this article could aid oil field operators to understand the impact of different parameters on immiscible WAG injection process and potentially help them to optimize production from their fields.