Modification of turbulence caused by cationic surfactant wormlike micellar structures in two-dimensional turbulent flow

An experimental study is performed to investigate the effects of the extensional rheological properties of drag-reducing wormlike micellar solutions on the vortex deformation and turbulence statistics in two-dimensional (2-D) turbulent flow. A self-standing 2-D turbulent flow was used as the experimental set-up, and the flow was observed through interference pattern monitoring and particle image velocimetry. Vortex shedding and turbulence statistics in the flow were affected by the formation of wormlike micelles and were enhanced by increasing the molar ratio of the counter-ion supplier to the surfactant, ξ, or by applying extensional stresses to the solution. In the 2-D turbulent flow, extensional and shear rates were applied to the fluids around a comb of equally spaced cylinders. This induced the formation of a structure made of wormlike micelles just behind the cylinder. The flow-induced structure influenced the velocity fields around the comb and the turbulence statistics. A characteristic increase in turbulent energy was observed, which decreased slowly downstream. The results implied that the characteristic modification of the 2-D turbulent flow of the drag-reducing surfactant solution was affected by the formation and slow relaxation of the flow-induced structure. The relaxation process of the flow-induced structure made of wormlike micelles was very different from that of the polymers.

Numerical simulation of the surfactants effect on the Taylor bubble in the PHP

Numerical simulation of the motion of a Taylor gas bubble in a heated small-diameter tube is carried out. Two models are used to describe the dependence of surface tension on temperature. In the first model, the surface tension decreases with temperature, and in the second, it increases, which corresponds to pure water and an aqueous surfactant solution. It is shown that the derivative sign affects the thickness of the liquid film around the bubble.

An Investigation on the Process of Reimbibition of Oil and Its Impact on Oil Recovery in the Yates Field

Summary In mixed- to oil-wet reservoirs characterized by intense natural fracturing where the dominant displacement mechanism is gravity drainage, surfactant injection can lead to a shift in wettability and incremental oil production. In some cases, oil can also reimbibe back into the rock matrix after the oil saturation has been reduced upon initial exposure to surfactant, suggesting limited permanence in the wettability shift. The reimbibition phenomenon is investigated in this paper using Amott cells. Three cationic surfactants (C12-, C12–16-, C16-based) with interfacial tensions (IFT) between 0.18 and 0.95 mN/m were preselected to be evaluated. Current application of the C12-based surfactant in the Yates field is considered successful based on incremental oil recovery seen during the treatment. Silurian dolomite (SD) rock samples were flooded with Yates crude oil before being aged at 60°C for 6 weeks. For the imbibition tests, the aqueous surfactant solution was set as the external phase within the Amott cell, and the recovery of oil was recorded periodically. After the imbibition tests ended, the rock samples were placed in an inverse Amott cell with the Yates oil as the external phase. Baseline tests were first conducted to show that without a surfactant in the oil or brine, no imbibition occurred. With a surfactant concentration of 3,000 ppm, oil recovery at the end of the imbibition tests varied from 34 to 60% of the original oil volume in the core sample. During the reimbibition test, a large amount of oil was able to reimbibe into the rock, displacing the brine. Most of the displacement occurred within the first 2 weeks. The net oil recovery, taken as the final volume of oil recovered in the imbibition test minus the final volume of oil reimbibed into the rock, ranged from 0 to 18%. Given the possibility of surfactant dilution in field applications, another set of tests was conducted with 1,500 ppm. A reduction in oil recovery during imbibition was observed for all the tested surfactants. Partition coefficients were determined for each of the tested surfactants, and the ion-pair mechanism was used to explain the net oil recovery results. Lastly, the impact of rock permeability on reimbibition was investigated. Results show increasing permeability may lead to a linear response in oil reimbibition; therefore, minimizing the permeability range when selecting rock samples may be necessary when conducting the reimbibition test. The importance of oil reimbibition is demonstrated in the experimental study, and we make an argument for conducting both the imbibition and reimbibition tests to better evaluate surfactant efficacy. The improved understanding of wettability alteration should lead to advancements in chemical enhanced oil recovery (EOR) designs for field treatments.

The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test

The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield. This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified. In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons. Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.

Pore Scale Study of the Effects of Wettability Alteration on Enhanced Oil Recovery

Drainage displacement at unfavorable viscosity ratios is often encountered in oil recovery process, which significantly limits the oil recovery. Surfactants have been extensively used as wettability modifier to improve the hydrocarbon recovery from rock matrix by imbibition, but little attention has been paid to the use of surfactant-aided wettability alteration to suppress fingering during displacement. In this study, we investigate the surfactant-aided immiscible displacement in oil-wet microfluidic chips. We find that the change of advancing contact angle by surfactant is velocity dependent and stable displacement can be achieved at low velocity when surfactant solution is used at the injection fluid. In comparison, fingering occurs at all capillary numbers for water injection, resulting in low oil recovery. Besides, the generation of oil ganglion during waterflooding and surfactant flooding exhibits completely different characteristics. Our study reveals the pore-scale mechanism of surfactant-aided wettability on the immiscible displacement, which is important for highly efficient oil recovery.

Flow Dynamics of Microemulsion-Forming Surfactants and its Implications for Enhanced Oil Recovery: A Microfluidic Study

The microfluidic experiments were conducted in this paper to clarify the flow dynamics of in situ microemulsion and further understand its EOR performances. Two kinds of 2.5D glass micromodel with varied depths of pore and throat are fabricated. One is designed for the imbibition tests, which consists of two fractures and a tight matrix. Another one is a fractured micromodel designed for the flooding tests. The micromodels are originally water wet, and can be altered to oil wet through the surface modification. At the same time, three microemulsion-forming surfactant solutions at the salinity of type I, II or III were prepared, respectively. Then the flow dynamics of these three surfactant solutions during imbibition and flooding process were visualized by the microfluidic experiments. Results show that the type I surfactant solution realizes the highest oil recovery rate in both water-wet and oil-wet imbibition micromodels. Meanwhile, the type III surfactant solution realize the highest oil recovery in both water-wet and oil-wet fractured micromodels.

Facile Fabrication of Nanoemulsions through the Efficient Catanionic Surfactants for Spontaneous Imbibition in Tight Oil Reservoirs: Experimental and Numerical Simulation

Spontaneous imbibition (SI) is an essential method for accelerating mass exchange between fracture and matrix in tight oil reservoirs. However, conventional systems such as brine and surfactant solution have limited imbibition effects, so there is still abundant remaining oil in the matrix. Nanoemulsion holds the most promising potential in improving tight oil recovery owing to the favorable surface activity and nanoscale droplets, but it still lacks economic and facile methods to fabricate nanoemulsions. Therefore, in this paper, we prepared a kind of O/W nanoemulsion of catanionic surfactants with a low dosage of surfactant and energy consumption, which was then used to assess spontaneous imbibition performance in Changqing outcrop cores by experimental and numerical simulation. We have fully considered the possible imbibition mechanisms of nanoemulsion including wettability alteration, IFT reduction, solubilization and emulsification, etc., and successfully applied to the nanoemulsion imbibition model. The model and experimental data were found to be in good agreement. The results showed that the imbibition rate and oil recovery factor of the nanoemulsion in the first 100 hours are lower than that of brine. In the late stage, we observed a longer equilibrium time and a faster and higher oil imbibition process in nanoemulsion with ultralow IFT. Finally, we confirmed that solubilization and emulsification is one of the domiant mechanisms for nanoemulsion imbibition by comparing with the modelling without considering solubilization and emulsification.

Fixed-Bed Modification of Zeolitic Tuffs and Their Application for Cr(VI) Removal

Natural clinoptilolite tuff (CL) and chabazite-clinoptilolite tuff (CH) were modified in fixed-bed column by immobilization of hexadecyltrimethylammonium bromide (HDTMA-Br), then investigated as a sorbent for inorganic anions of Cr(VI). The proposed modification technique combined with surfactant solution batching allows minimizing the surfactant loses through foaming and crystallization and creation of stable organic coverage. The HDTMA loading depended on the mineral composition of the zeolitic tuff, the topology of its external surface, and process conditions. The maximum surface coverage was obtained by gradually dosing surfactant solution in the smallest volume of batches and corresponded up to 100% and 182% of external cation exchange capacity (ECEC) for mono and double layer coverage, respectively. In case of mono layer coverage, modification proceeds until the exhaustion of surfactant in supply solution, while in the double layer one, until equilibrium of HDTMA concentration in both zeolitic and liquid phases was established. The efficiency of Cr(VI) uptake by prepared surface modified zeolites (SMZs) increased with increasing of HDTMA loading. In the case of mono layer SMZs, the capacities of CH-HDTMA and CL-HDTMA were 10.3 and 5.4 mg/g, respectively, while in the case of double layer SMZs, the amount of Cr uptake on CH-HDTMA and CL-HDTMA were 16.8 and 15 mg/g, respectively. Ion exchange is the predominant mechanism of Cr(VI) sorption but it takes place only if modification resulted in at least partial double layer coverage. The XPS analysis reveals Cr(VI) reduction to a less-toxic Cr(III) by the electron donating N-containing groups and by reaction with Fe+2 ions on the zeolite external surface.