RESUMO
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.
RESUMO
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.
RESUMO
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.