Study on Water-Soluble Phenolic Resin Gels for High-Temperature and High-Salinity Oil Reservoir.

High water cut of produced fluid is one of the most common problems in reservoir development. At present, injecting plugging agents and other profile control and water plugging technologies are the most widely used solutions. With the development of deep oil and gas resources, high-temperature and high-salinity (HTHS) reservoirs are becoming increasingly common. Conventional polymers are prone to hydrolysis and thermal degradation under HTHS conditions, making polymer flooding or polymer-based gels less effective. Phenol-aldehyde crosslinking agent gels can be applied to different reservoirs with a wide range of salinity, but there exist the disadvantage of high cost of gelants. The cost of water-soluble phenolic resin gels is low. Based on the research of former scientists, copolymers consisting of acrylamide (AM) and 2-Acrylamido-2-Methylpropanesulfonic acid (AMPS) and modified water-soluble phenolic resin were used to prepare gels in the paper. The experimental results show that the gelant with 1.0 wt% AM-AMPS copolymer (AMPS content is 47%), 1.0 wt% modified water-soluble phenolic resin and 0.4 wt% thiourea has gelation time of 7.5 h, storage modulus of 18 Pa and no syneresis after aging for 90 days at 105 °C in simulated Tahe water of 22 × 104 mg/L salinity. By comprehensively comparing the effectiveness of the gels prepared by a kind of phenolic aldehyde composite crosslinking agent and modified water-soluble phenolic resin, it is found that the gel constructed by the modified water-soluble phenolic resin not only reduces costs, but also has shorter gelation time and higher gel strength. The oil displacement experiment with a visual glass plate model proves that the forming gel has good plugging ability and thus improves the sweep efficiency. The research expands the application range of water-soluble phenolic resin gels, which has an important implication for profile control and water plugging in the HTHS reservoirs.

A Study on the Thermal Degradation of an Acrylamide and 2-Acrylamido-2-Methylpropanesulfonic Acid Copolymer at High Temperatures.

As a temperature-resistant and salt-resistant polymer, acrylamide and 2-acrylamide-2-methylpropane sulfonic acid (abbreviated as AM-AMPS) copolymer is currently widely used in drilling, water control and oil production stabilization, enhanced oil recovery and other fields, but its stability under high temperature has been less studied. The degradation process of the AM-AMPS copolymer solution was studied by measuring viscosity, the degree of hydrolysis, and weight-average molecular weight at different temperatures and aging time. During the high-temperature aging process, the viscosity of the AM-AMPS copolymer saline solution first increases and then decreases. The combined action of the hydrolysis reaction and the oxidative thermal degradation leads to the change of the viscosity of the AM-AMPS copolymer saline solution. The hydrolysis reaction of the AM-AMPS copolymer mainly affects the structural viscosity of its saline solution through intramolecular and intermolecular electrostatic interactions, while the oxidative thermal degradation mainly reduces its molecular weight by breaking the main chain of the copolymer molecules, reducing the viscosity of the AM-AMPS copolymer saline solution. The content of AM and AMPS groups in the AM-AMPS copolymer solution at various temperatures and aging time was analyzed using liquid nuclear magnetic resonance carbon spectroscopy, demonstrating that the hydrolysis reaction rate constant of AM groups was significantly higher than that of AMPS groups. The contribution values of hydrolysis reaction and oxidative thermal degradation of the AM-AMPS copolymer at different aging time to viscosity were quantitatively calculated at temperatures ranging from 104.5 °C to 140 °C. It was determined that the higher the heat treatment temperature, the smaller the contribution of hydrolysis reaction to viscosity, while the bigger the contribution of oxidative thermal degradation to the viscosity of the AM-AMPS copolymer solution.

Investigation of Polymer Gel Reinforced by Oxygen Scavengers and Nano-SiO2 for Flue Gas Flooding Reservoir.

Polymer gel plugging is an effective technique for gas mobility control in flue gas flooding reservoirs. However, the performance of polymer gels is extremely susceptible to the injected flue gas. A reinforced chromium acetate/partially hydrolyzed polyacrylamide (HPAM) gel, using thiourea as the oxygen scavenger and nano-SiO2 as the stabilizer, was formulated. The related properties were evaluated systematically, including gelation time, gel strength, and long-term stability. The results indicated that the degradation of polymers was effectively suppressed by oxygen scavengers and nano-SiO2. The gel strength would be increased by 40% and the gel kept desirable stability after aging for 180 days at elevated flue gas pressures. Dynamic light scattering (DLS) analysis and Cryo-scanning electron microscopy (Cryo-SEM) revealed that nano-SiO2 was adsorbed on polymer chains by hydrogen bonding, which improved the homogeneity of gel structure and thus enhanced the gel strength. Besides, the compression resistance of gels was studied by creep and creep recovery tests. The failure stress of gel with the addition of thiourea and nanoparticles could reach up to 35 Pa. The gel retained a robust structure despite extensive deformation. Moreover, the flow experiment indicated that the plugging rate of reinforced gel still maintained up to 93% after flue gas flooding. It is concluded that the reinforced gel is applicable for flue gas flooding reservoirs.

Novel Strategy of Polymers in Combination with Silica Particles for Reversible Control of Oil-Water Interface.

Hybrid smart emulsification systems are highly applicable in manipulating oil-in-water (O/W) droplets. Herein, novel switchable block polymers containing both zwitterionic and tertiary amine pendent groups were designed and synthesized to combine with charged silica particles to stabilize the O/W emulsion responsive to pH. This study was carried out in O/W emulsions stabilized with the polymer and silica particles under different pH conditions. The emulsion system was also simulated using molecular dynamics simulation to reveal the mechanism at molecular levels, thus gaining insight into the relationships between the emulsifying properties and the molecular interaction of the mixed system. Upon acidification of the continuous aqueous phase, protonated polymers with excellent hydrophilicity were induced by charged silica particles to cause rapid emulsion coalescence. In alkaline media, the mixed system conversely stabilized the O/W emulsions, cutting polymer consumption by over three-quarters. The emulsification and demulsification can be switched alternately by tuning the pH conditions. The applications exhibited excellent efficiency in separating heavy oil/water emulsions and proved the high conversion rate in emulsion polymerization. Overall, with this novel strategy to relieve tedious modifications on particle surfaces and massive consumption of polymers, the designed responsive emulsification systems can impart intelligent and controllable chemical reactivity to emulsions on demand in a more affordable and sustainable way.

Preparation Method and Performance Evaluation of a Gel Based on AM/AMPS Copolymer.

Polymer gels have been widely used in high water cut oilfields for profile control and water plugging. It is urgent to develop a gel suitable for the Tahe Oilfield (Temperature: 130 °C, salinity: 2.2 × 105 mg/L) in China. A stable gel was prepared by using an acrylamide (AM)/2-acrylamide-2-methyl propanesulfonic acid (AMPS) copolymer crosslinked with urotropin (HMTA), hydroquinone (HQ), thiourea and Nano-SiO2. This paper covers a step-by-step process for designing gels based on experience with preparing gels. A wide range of combinations between polymers and crosslinking agents with and without stabilizers were investigated, and the results indicated that there is an optimal value of AMPS content of AM/AMPS copolymers in the preparation of gels. Increasing the mass fraction of copolymer and using stabilizer enhanced the performance of gel, but an excessive amount of crosslinking agent was not conducive to the stability of gel. The work optimized the formula of plugging agent suitable for the high temperature and high salt (HTHS) condition in the Tahe Oilfield. The gelling solution had a long gelation time of 20 h. The gel had high strength (Sydansk's gel-strength code of "G") with storage modulus of 12.9 Pa and could be stable for half a year at 130 °C and 2.2 × 105 mg/L of salinity. The plate model that could be heated and pressurized was used to simulate the oil flooding and profile modification under the condition of the Tahe Oilfield for the first time. The experiment results showed that the oil recovery could be increased by 13.22% by subsequent water flooding under heterogeneous formation condition. Therefore, it was fully confirmed that the plugging performance of AM/AMPS phenolic gel prepared in the work was excellent. The information provided in the study could be used as a reference for the design and evaluation of polymer gels in other HTHS reservoirs.

Probing the Effect and Mechanism of Flue Gas on the Performance of Resorcinol/Hexamethylenetetramine-Based Polymer Gel in Flue Gas Flooding Reservoir.

Polymer gel plugging is an effective method for gas mobility control in flue gas flooding reservoirs. However, the effect and mechanism of flue gas on the performance of polymer gels have rarely been reported. In this study, a polymer gel was prepared by cross-linking hydrolyzed polyacrylamide (HPAM) and resorcinol/ hexamethylenetetramine (HMTA) to illuminate the influencing mechanism of flue gas composition on gel. The gel rheological testing results showed that flue gas promoted gelation performance, whereas it seriously threatened gel long-term stability, especially at high pressure conditions. The influence of CO2 on the polymer gel had the characteristic of multiplicity. The hydrodynamic radius (Rh) and the initial viscosity of HPAM solution decreased in the presence of CO2. Nonetheless, the dissolved CO2 expedited the decomposition rate of HMTA into formaldehyde, which promoted the cross-linking process of the HPAM, leading to a shorter gelation time. Oxidation-reduction potential (ORP) tests and Fourier transform infrared spectroscopy (FTIR) analysis indicated that O2 played a leading role in the oxidative degradation of HPAM compared to CO2 and threatened the gel long-term stability at elevated gas pressures. To address the adverse effects caused by flue gas, it is highly desirable to develop polymer gels by adding oxygen scavengers or strengthening additives.

Investigation of Nanoclay-Surfactant-Stabilized Foam for Improving Oil Recovery of Steam Flooding in Offshore Heavy Oil Reservoirs.

This study presents a study of nanoclay-surfactant-stabilized foam to improve the oil recovery of steam flooding in offshore heavy oil reservoirs. The foam stability and thermal resistance studies were first performed to investigate the influence of nanoclay on the stability and thermal resistance properties of the foam system. Then, the sandpack flooding tests were conducted for investigating the resistance factor and displacement abilities by nanoclay-surfactant-stabilized foam. The results showed that the nanoclay-surfactant-stabilized foam has excellent foaming ability and foam stability at 300 °C, which can be used in steam flooding for offshore heavy oil reservoirs. The resistance factor is greater than 30 at 300 °C when the gas-liquid ratio ranges from 1 to 3, which indicated that the nanoclay-surfactant-stabilized foam has good performance of thermal resistance and plugging effect. The heterogeneous sandpack flooding test showed that the nanoclay-surfactant-stabilized foam can effectively divert the steam into the low-permeability area and improve the sweep efficiency, thus improving heavy oil recovery of steam flooding. Therefore, the nanoclay-surfactant-stabilized foam flooding has a great potential for improving oil recovery of steam flooding in offshore heavy oil reservoirs.

Selection of Optimum Surfactant Formulations with Ultralow Interfacial Tension for Improving the Oil Washing Efficiency.

Ultralow oil-water interfacial tension (IFT) has provided an important basis for screening optimum surfactant formulation for improving the oil washing efficiency. Thus, it is of great significance to further investigate the selection method for surfactant systems with ultralow IFT. In this study, a selection of surfactant systems with ultralow IFT was simplified by a method of comparing the equivalent alkane carbon number (EACN) of crude oil with the minimum alkane carbon number (n min) of surfactant mixtures. The results show that the ultralow IFT can be achieved when the n min of optimum surfactant formulation is equal to the EACN of crude oil. Meanwhile, the oil washing efficiency experiments show that the oil washing efficiency increases with the decrease of IFT, and the optimum surfactant formulation with ultralow IFT has the highest oil washing efficiency. This study provides a more efficient way for selecting optimum surfactant formulation systems with ultralow IFT for improving the oil washing efficiency.