Mobility Control Ability Research Articles

Study on the mobility control ability of a quaternary ammonium salt active polymer for oil flooding

Mobility control ability is an important property of polymer used in oil displacement. This work initially investigates the temperature and salt resistance, steady-state rheology, dynamic viscoelasticity, and long-term stability of a quaternary ammonium salt active polymer (AM/AMPS/DMCA). Subsequently, an examination was conducted to evaluate the static adsorption ability of AM/AMPS/DMCA on the surface of quartz sand, as well as the dynamic retention property within cores. Finally, the mobility control ability and oil displacement capacity of AM/AMPS/DMCA under various injection conditions was investigated in this study. The findings illuminate the superior attributes of AM/AMPS/DMCA, including its remarkable temperature and salt endurance, alongside its long-term stability, presenting a significant advancement over traditional binary polymers like AM/AMPS. Notably, AM/AMPS/DMCA exhibits a predominantly elastic modulus, which enhances its movement and deformation inside porous media. Furthermore, it has been shown that the resistance factor and residual resistance factor achieved by the 2000 mg/L AM/AMPS/DMCA solution in the core of 96.6 mD were 184.50 and 46.95, respectively. The enhanced oil recovery (EOR) value of 0.6 PV of AM/AMPS/DMCA achieved 30.48% in the core of 588.8 mD. This study not only demonstrates the capability of AM/AMPS/DMCA in EOR but also facilitates the understanding of the mobility control mechanism of polymers in porous media, offering valuable empirical guidance for the field application of polymers.

Naturally Occurring Vegetation Connectivity Facilitates Ant-Mediated Coffee Berry Borer Removal.

Vegetation connectivity is an essential aspect of the habitat complexity that impacts species interactions at local scales. However, agricultural intensification reduces connectivity in agroforestry systems, including coffee agroecosystems, which may hinder the movement of natural enemies and reduce the ecosystem services that they provide. Ants play an important role in regulating the coffee berry borer (CBB), which is the most damaging coffee pest. For arboreal ant communities, the connections between trees are important structures that facilitate ant mobility, resource recruitment, foraging success, and pest control ability. To better understand how connectivity impacts arboreal ants in coffee agroecosystems, we conducted an experiment to assess the impact of artificial (string) and naturally occurring vegetation (vines, leaves, branches) connectivity on Azteca sericeasur behavior on coffee plants. We compared ant activity, resource recruitment, and CBB removal rates across three connectivity treatments connecting coffee plants to A. sericeasur nest trees: vegetation connectivity, string, and control (not connected) treatments. We found higher rates of ant activity, resource recruitment, and CBB removal on plants with naturally occurring vegetation connections to A. sericeasur nest trees. Artificial connectivity (string) increased the rates of resource recruitment and CBB removal but to a lesser extent than vegetation connectivity. Moreover, vegetation connectivity buffered reductions in ant activity with distance from the ant nest tree. These results reinforce how habitat complexity in the form of vegetation connectivity impacts interspecific interactions at the local scale. Our results also suggest that leaving some degree of vegetation connectivity between coffee plants and shade trees can promote ant-mediated biological pest control in coffee systems.

Factors influencing the mobility control ability of diutan gum‐enhanced foam in porous media

AbstractDiutan gum (DG) is an anionic polysaccharide produced by Sphingomonas sp. ATCC 53159. The DG‐enhanced foam (DGEF) formed by the DG and foam has great application potential in enhanced oil recovery. In this research, the influence of injection parameters on DGEF was studied by conducting orthogonal experiment, with residual resistance coefficient (Rff) as the main evaluation index. The micro‐state of the foam was observed using an etching model and scanning electron microscope. The mechanism of different factors on the mobility control ability of the foam was discussed based on the apparent viscosity and surfactant depletion. The results show that the Rff of foam is correlated with the apparent viscosity, and the foam with high apparent viscosity had a good flow control ability. The calculation of the surfactant depletion shows that the bubble stability decreased significantly when the concentration of Sodium alpha‐olefin sulfonate (AOS) cannot meet the minimum stabilization concentration, thus weakening the mobility control ability. Based on the study of crude oils, the presence of oil phase will seriously weaken the mobility control ability of DGEF, but the effect of oil with higher content of resin and asphaltene will be relatively weak.

Experimental Study on the Enhanced Oil Recovery Mechanism of an Ordinary Heavy Oil Field by Polymer Flooding.

It is widely known that in the water flooding development process of ordinary heavy oil, the fingering phenomenon is obvious, there are a lot of unswept areas, and absolutely, the recovery is really very low. In addition, for some shallow and thin ordinary heavy oil reservoirs limited by the geological conditions of the reservoir, the thermal recovery technology also has serious heat loss and high development cost. Therefore, there is an urgent need to transform the development and further improve the enhanced oil recovery (EOR). In this paper, the mechanism of EOR by polymer flooding was investigated for high-porosity and high-permeability terrestrial ordinary heavy oil reservoirs. Through laboratory experiments, we analyzed the characteristics of oil-water relative permeability curves, mobility control ability, and microscopic seepage characteristics during polymer flooding of ordinary heavy oil reservoirs. On this basis, the effect of the mobility ratio on seepage characteristics and the mechanism of EOR enhancement were clarified. The results show that the polymer can effectively improve the mobility control effect of the displacing fluid. As the polymer solution and ordinary heavy oil have the characteristics of high viscosity and low mobility, there is a minimum mobility ratio in the process of polymer flooding. Namely, the characteristics of dual low mobility exist in the process of polymer flooding for the ordinary heavy oil. It effectively enhances the profile control and plugging ability of the polymer, thus expanding the sweep volume of larger pores and improving the displacement efficiency of smaller pores. Based on the two factors mentioned above, it is found that the dual low mobility characteristics can improve the recovery of ordinary heavy oil by polymer flooding. Therefore, it is proposed that an enhanced profile control and plugging effect due to the dual low mobility characteristics is an important EOR mechanism for ordinary heavy oil development by polymer flooding.

The development of a smart gel for CO2 mobility control in heterogeneity reservoir

CO2 flooding is regarded as one of the most effective ways to enhance oil recovery for unconventional oil and gas reservoirs, that is also conducive to the capture and storage of CO2. However, due to the heterogeneity of the reservoir, the gas channeling of CO2 becomes more serious, limiting the sweep efficiency of CO2 flooding. Herein, to make the most use of CO2 flooding, a CO2-responsive smart gel system is designed to improve the formation profile and control the mobility of CO2. Through rheological tests, the basic properties, such as shear resistance, viscoelasticity and responsiveness, are evaluated. The system has good viscoelastic and shear resistance, and can quickly form high strength gel within 150 s. At the same time, the self-assembly mechanism of the system is revealed by SEM. The influence of permeability, injection concentration and volume of smart gel on the plugging performance of the CO2-responsive smart gel system are also explored. Finally, the mobility control ability and EOR performance of the CO2-responsive smart gel system are revealed by the double pipes flooding experiments. This work puts forward a new idea of enhancing oil recovery for CO2 flooding with the aid of CO2-responsive smart gel.

Experimental study of an amphiphilic graphene oxide based nanofluid for chemical enhanced oil recovery of heavy oil

Amphiphilic GOC nanosheets in situ form a viscoelastic emulsion, which achieves mobility control ability to enhance oil recovery.

Experimental Study on Early Polymer Injection Timing of Heavy Oil Reservoir in Bohai Sea

The polymer flooding of ordinary heavy oil reservoirs in Bohai Sea can improve the crude oil recovery by advancing the injection time of polymer flooding. The better the injection time is, the higher the enhanced recovery is, and the greater the income is. Based on Bohai Oilfield, the polymer application system was characterized in the laboratory, and then polymer flooding experiments were carried out at different times using one-dimensional core model. The results show that: 1) polymer AP-P4 can establish good mobility control ability (RF=107, RRF=28.5) under the target reservoir conditions; 2) Under the experimental conditions, the best time for polymer injection is to switch to polymer injection after 0.203PV water injection, and the oil recovery can be increased by 27.73%. Early polymer injection technology is very beneficial to polymer flooding in offshore oil fields.

Potential application of dispersed particle gel strengthened alkali as a novel combination flooding system for enhanced oil recovery

A novel dispersed particle gel strengthened alkali (DPGSA) combination flooding system was proposed for enhanced oil recovery in high water cut mature oilfields. When crude oil and the alkali in the DPGSA combined flooding system interact, petroleum soap is produced, causing a lowering of the interfacial tension (IFT). It can reverse the oil-wetted rock surface to a water-wetted rock surface. The dispersed particle gel (DPG) has viscosity, and the particles are less affected by alkali, temperature, and aging time. Additionally, DPG can strengthen the mobility control ability through single particle expansion and micro coalescence of multiple particles at a specific temperature. Compared with the alkali and polymer/alkali (PA) flooding system, the DPGSA combination flooding system has better viscosity retention and mobility control ability. Based on the sand-pack flow experiment, the DPGSA combination flooding system has good injectability and profile improvement ability. The dispersed particle gels plug the macropore throats through adsorption and bridging. Through the synergistic effect of reducing IFT and increasing swept volume, the DPGSA combination flooding system also shows excellent performance in EOR. The DPGSA combination flooding system is better than the alkali and polymer/alkali (PA) combination flooding system. It can be used as a new alternative to enhance oil recovery in high water cut and highly heterogeneous mature oilfields.

Enhanced oil recovery performance and mechanism of a wormlike micelles flooding system with zwitterionic-anionic surfactants

Surfactant-based wormlike micelles (WLMs) have been proven to be efficient in improving oil recovery due to their high viscosity and low oil/water interfacial tension (IFT). In this study, a novel WLMs oil displacement system was developed by mixing zwitterionic surfactant (Erucylamido propyl betaine, EAPB) and anionic surfactant (Sodium dodecylsulfate, SDS) at the mass ratio of 1.5:1. The viscosity, IFT and emulsification properties were studied by rheometry, interfacial tensiometry and bottle testing, respectively. The core and etched glass micro-model oil displacement tests were conducted to investigate the oil recovery efficiencies and the related mechanism. The results show that the EAPB-SDS combination system exhibits shear thickening compared to that of sole EAPB system due to the electrostatic attraction between SDS and EAPB. The viscosity is first increased and then decreased with the increase in pH, temperature and salinity. The IFT is decreased with pH, while it is first decreased and then increased with the increase of temperature and salinity. The EAPB-SDS combination system with mass concentration of 0.3% can enhance oil recovery by 25.91% and 19.79% after water flooding in homogeneous and heterogeneous cores, respectively. The high viscosity makes the system to exhibit good mobility control ability, while the low IFT contributes to the peeling and emulsification of residual oil, thereby significantly improving the oil displacement performance.

Research on Percolation Characteristics of a JANUS Nanoflooding Crude Oil System in Porous Media.

According to the research status of low-permeability reservoir development, in order to find an intelligent and efficient displacement method, a Janus smart nanocapsule (embedding nanomaterials with surfactant function into the polymer) is developed in this paper. There are two kinds of phase fluids in the migration of porous media, the initial Janus intelligent microcapsule slow-release liquid (dissolved and undissolved AP-g-PNIPAAM and Janus functional particle ternary dispersion) and the later AP-g-PNIPAAM and Janus functional particle binary dispersion. Comprehensively, using the indoor oil displacement experiment, the seepage characteristics of the Janus smart nanocapsule (JSNC) in porous media are studied, and their macro and micro oil displacement mechanisms are revealed. Research shows that Janus intelligent microcapsules have good mobility control ability in low-permeability heterogeneous reservoirs. The displacement performance of stepped differential pressure shows that the displacement medium can expand the swept volume. The research results presented can show that the JSNC oil displacement system has great application potential for the development of low-permeability reservoirs.

Study on the mechanism of W/O emulsion flooding to enhance oil recovery for heavy oil reservoir

W/O emulsion is able to effectively improve the sweep volume and oil recovery factor during the waterflooding due to its strong mobility control ability, it has a great EOR appliance for heavy oil reservoirs. In this study, emulsion stability, droplet size distribution (DSD) and rheological behavior at different water content and salinity were investigated. Then core flooding experiments was conducted to study the oil displacement efficiency of W/O emulsion formed at different water content, and a visual micromodel was designed to observe the mechanisms of W/O emulsion flooding at the pore-throat scale. Results showed that W/O emulsion had the characteristics of the pseudoplastic fluid, exhibiting shear thinning behavior. Emulsion stability and DSD uniformity became worse with the increment of water content. Emulsion viscosity increased with water content varying from 20% to 40%, and then decreased as water content rose from 40% to 90%. Whereas Emulsion stability decreased slightly with the salinity increasing due to its high content of polar components inherent in heavy crude oil. The piston-like displacement could be formed due to its high mobility control ability caused by high viscosity. Meanwhile, the adverse effects caused by formation heterogeneity and viscosity fingering could be inhibited. After subsequent water breakthrough, emulsion droplets produced viscoelastic deformation during waterflooding. The emulsification carrying-on, block, and drag effect were the main mechanism of W/O emulsion flooding at the pore level. The findings of this study are significant for the enhanced oil recovery in heterogeneous heavy oil reservoirs.

The injection method of a hydrophobic associated polymer with evident salt thickening property

A comb like micro-blocked hydrophobic association polymer (CBHAP) with evident thickening property in high salinity and weak thickening property in fresh water was developed. Based on the unique property, we designed the injection strategy that polymer in fresh water with low viscosity was injected into the cores to improve injectivity and high salinity water was used to perform subsequent water flooding to improve mobility control ability. The factors influencing on the injectivity as well as mobility control ability were researched by the core flooding experiments. As a result, pressure fluctuation was found in the subsequent water flooding from 0.7 PV to 1.5 PV, showing obvious variation of viscosity in the cores. The phenomenon was believed to improve mobility control ability. In addition, the positive correlation between polymer concentration, salinity, injected volume and the fluctuation was found. The designed injection method for the polymer can be used to solve injectivity issue as well as improve mobility control ability in high salinity reservoir.

Influence of different oil types on the stability and oil displacement performance of gel foams

Foam stability drives its mobility control ability and displacement effects. In addition to the chemical composition of the foam system, the oil types are also a key element that affects the stability of the foam. Three kinds of crude oil with different components were used to explore the stability and oil displacement ability of the gel foam system. And then, the foam performance, coarsening behavior, emulsifying properties, plugging ability, and oil recovery enhancement of oil-bearing gel foam were examined. Experimentally, our results demonstrate that the more polar heavy components (asphaltene and resin) in crude oil, the gel foam exhibits higher foam stability performance when the oil saturation is 0–20%. Owing to the stable crude oil emulsion reduces fluid loss and hinders the movement of oil droplets within the lamella, a highly stable pseudo-emulsion liquid film is formed, which reduces the rupture of the oil-bearing gel foam. The results of oil displacement experiments show that LD-2 crude oil with the highest concentration of heavy oil components produced the most stable oil-containing gel foam, with a plugging rate of 95.33% and an enhanced recovery rate of 23.1%. In addition, different sampling points are set for the sandpack model to observe the stable state and migration of the oil-bearing gel foam in the porous medium. This study revealed the stability of oil-bearing gel foams under different crude oil types and provides a theoretical basis for applying gel foam in enhanced oil recovery of different types of crude oil reservoirs.

The synergistic role of silica nanoparticle and anionic surfactant on the static and dynamic CO2 foam stability for enhanced heavy oil recovery: An experimental study

CO2 foam is a promising candidate in enhanced oil recovery and reducing anthropogenic CO2 emission through geo-sequestration due to its CO2 mobility control ability. However, instability of CO2 foam stabilized solely by surfactant strongly retards its application. Here, two types of silica nanoparticles (NPs) with varied hydrophobicity are used with sodium bis(2-ethylhexyl) sulfosuccinate (AOT) to increase CO2 foam stability. Through foamability and foam stability experiments, together with complementary experiments such as measurements of CO2-water interfacial tensions, particle zeta potential, and adsorption isotherm of surfactant, the stabilization mechanisms of AOT-NPs aqueous dispersions on the CO2 foam films are revealed. Oil recovery experiments are performed in an oil-wet micromodel where high permeability channels are included to mimic wormholes in unconsolidated sandstone reservoirs during sand production. Results show that the nanoparticle surface hydrophobicity strongly influences the interactions between particles and AOT. Partially hydrophobic NPs (NPB) are much more efficient in generating and stabilizing CO2 foam than hydrophilic NPs (NPA) when mixed with AOT in a proportion of 1: 0.16 (wt%/wt%). AOT-NPB dispersions improve the recovery in two aspects: First, the synergistic interactions between AOT and NPB leads to the adsorption of AOT on particle surfaces, thus enhancing mechanical strength of bubbles. High quality foam encompasses a fine foam texture and provides higher resistance to the gas flow, leading to a more uniform sweep. Second, AOT-NPB dispersions reduces oil/water IFT, promotes emulsification forming oil in water (O/W) emulsions, and alters glass surface wettability, leading to substantial incremental oil recovery.

Performance of Chromic Acetate-HPAM Gel for Flue Gas Mobility Control in Low-Permeability Reservoir

Chromium acetate-HPAM gel is developed to solve the gas channeling problem in low-permeability flue gas flooding reservoirs. Polyacrylamide with low molecular weight of 2 million is optimized as the main agent to construct an organic chromium gel system. The acid resistance performance and blocking capacity of the gel system are evaluated afterwards. It is revealed by the tests that acid components in flue gas have a severe impact on the gelation time, strength as well as long-term stability of the cross-linked gels. Rheological tests show that the gel system embodies with high elastic modulus in flue gas environment at 42°C, which ensures its favorable performance in core flooding tests. After gel application in cores, the permeability reduction can reach up to 99% and 97% separately while water flooding and flue gas flooding. The chromium acetate-HPAM gel exhibits perfect mobility control ability and possesses immense potential as regulating blocking system in low-permeability flue gas flooding reservoirs.

Ethanol enhanced anionic surfactant solubility in CO2 and CO2 foam stability: MD simulation and experimental investigations

CO2 foam has been widely scrutinized as a potential candidate in enhanced oil recovery while reducing CO2 emissions through geo-sequestration due to the high-efficiency CO2 mobility control ability. However, its application has been retarded partially because of the limited solubility of commercial and environmentally friendly surfactants in supercritical CO2. In this work, the challenge of limited solubility of surfactant sodium bis(2-ethylhexyl) sulfosuccinate (AOT) in CO2 is overcome by using ethanol as a co-solvent. The presented MD simulation reveals the underlying mechanism of the ethanol increased solubility of AOT in CO2 and the subsequently water-CO2 interfacial properties favorable for a stable CO2 foam. Experimental observation is in good accordance with the MD simulation that foamability and foam stability both significantly increase with ethanol as co-solvent, and their dependence on ethanol content. With ethanol as co-solvent to assist the dissolution of AOT in CO2, the CO2 foam has a high stiffness and the foam film has a high dilational modulus under high pressure of 15 MPa, which explain the stable CO2 foam. Experiments also show that ethanol helps the foam regeneration, making the practical oil field application of the presented system even more promising.

Experimental Study on the Effect of Polymer Injection Timing on Oil Displacement in Porous Media

It has been proven that polymer injection at early times is beneficial to offshore heavy oil recovery. It is of significant importance to optimize the polymer injection timing and decide the residual oil distribution after polymer flooding. Aiming at a specific offshore heavy oil reservoir in Bohai, China, the optimum polymer injection timing is investigated through laboratory experiments. The influence of polymer injection timing on oil displacement and remaining oil distribution is analyzed by combining macroscopic and microscopic flooding experiments. The results reveal that the optimum polymer injection timing should be close to the water breakthrough, i.e., just before the waterflooding front reaches the outlet of the core. In addition, the waterflooding front position is analytically solved by using the Buckley–Leverett method and verified by experimental results, which supply an approach to predict the polymer injection timing. When polymer is injected before the waterflood front reaches the outlet of the core, the mobility control ability of polymer solution can reduce the fraction of bypassed volume of the reservoir by waterflooding. The early injected polymer mainly enters the high permeability zone, which works positively in two ways. Firstly, it improves the oil displacement efficiency of the high permeability zone. Secondly, the polymer establishes a flow resistance in the high permeable zones, thus improving the sweep efficiency in the low and medium permeability zones. However, our residual oil distribution experiments illustrate that there is still a large amount of oil remaining in the low and medium permeability zones. Therefore, it is necessary to explore additional EOR methods to recover the abundant residual oil.

Salt induced shear thickening behavior of a hydrophobic association polymer and its potential in enhanced oil recovery

Shear thickening solution is rarely encountered but the solution with low concentration and high salinity is really desired in enhanced oil recovery. In this paper, we developed a comb micro-block hydrophobic association polymer (CBHAP). The polymer solution with high salinity showed an obvious shear thickening behavior, even if the polymer concentration was very low (1 g/L). In addition, with the increase in salinity (> 20 g/L) and temperature, shear thickening phenomenon will be more obvious. We analyzed that the unique rheological behavior was influenced by the comb micro-blocked structure and the forces transition from intramolecular to intermolecular when the curled polymer chains were stretched under shearing. In porous media, high permeability and low flow rate were beneficial to achieve the shear thickening flow. The unique property will endow CBHAP better mobility control ability than conventional polymers, especially in high permeability reservoirs or fractured reservoirs.

Experimental investigation of amine-surfactant CO2 foam for smart mobility control during CO2 flooding

Amine-surfactant can be converted to be cationic surfactant in water solution saturated with CO2, which can enhance their foaming ability and foam stability, and the foaming ability can be switched off or on by CO2 or replacing with N2 with heating, so the amine-surfactants have great potential for smart mobility control to gas channeling during CO2 flooding. In this study, three alkyl propyl dimethylamines with different carbon chain length (R = 11, 17 and 22, named as UC11AMPM, UC17AMPM, and UC22AMPM, respectively), were investigated as CO2 responsive foam agent, and their foam performance under static and dynamic condition was tested up to 130 °C and 10.5 MPa using a visualized foam meter and a sand-pack flooding setup. The influence of carbon chain length on bulk solution viscosity, surface activity, foaming ability, and foam quality on bulk foam stability were measured and analyzed. The experimental results indicate that the three amine surfactants all demonstrate well CO2 responsibility and CO2 foaming ability, and show well switchable by CO2 and N2 at high temperature and high pressure (HTHP) condition. With the carbon chain length increasing, the surfactant shows higher absorption on the foam films, and bulk solution has a higher viscosity, which can decrease de-foam velocity and enhance the foam stability, as a result, the surfactant shows higher mobility control ability.

Solution Properties and Displacement Characteristics of in situ CO2 Foam System for Enhanced Oil Recovery

AbstractCarbon dioxide (CO2) foam flooding has been shown to enhance oil recovery. However, large‐scale adoption has been restricted by issues with transportation of CO2 and equipment corrosion. In situ CO2 foam generation can possibly overcome these issues. In this article, a CO2 sustained‐release system was first optimized for the CO2 production rate and production efficiency. Then, the dissolution capacity and plug‐removing ability of the sustained‐release system were evaluated. Visual experiment and parallel sand pack flooding tests were conducted to verify the formation, propagation of in situ CO2 foam, and the feasibility of this technique. The results indicated that the sustained‐release system had benign ability to lower injection pressure and improve injectability. Moreover, in situ CO2 foam flooding could obtain high oil recovery due to favorable mobility control ability, interfacial tension reduction capacity, and heterogeneity improvement. All the experiments demonstrated that the in situ CO2 foam technique has great potential for enhanced oil recovery in the Bohai oilfield.