Effect of AMPS(2-acrylamido-2-methylpropane sulfonic acid) content on the properties of polymer gels

Zhang, Tian-Ci; Ge, Jijiang; Wu, Hao; Guo, Hongbin; Jiao, Baolei; Zhou, Qian

doi:10.1016/j.petsci.2022.01.006

Cited by 23 publications

(14 citation statements)

References 22 publications

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“…Therefore, the gel strength decreases, and the gelation time increases as AMPS content increases, especially while the AMPS content is greater than 50%. Zhang et al [ 24 ] have also found that there is an optimal value of AMPS content in polymers when gels form. The copolymer of 30% AMPS content was chosen in the follow-up experiments.…”

Section: Resultsmentioning

confidence: 99%

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

Ran

Zhang

Jiang

et al. 2022

Gels

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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.

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Section: Resultsmentioning

confidence: 99%

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

Ran

Zhang

Jiang

et al. 2022

Gels

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“…169 There are also gel systems consisting of AAm, MBAA/AAmA acrylamide (AAm), sodium alginate (SA), N,N-methylenebis(acrylamide) (MBAA), and N,N,N′,N′-tetramethylethylenediamine (TEMED), 23 which are degraded in brine. 133 However, these gels were generally particle gels, formulated from in situ polymer gels, but the particle gels had a large contact area with the breaking solution during the immersion process, so the experimental results were all preferable. The unstable main agent can be chosen to make the gel degrade naturally at a certain temperature.…”

Section: Oxidation Breakingmentioning

confidence: 99%

Progress and Prospects of In Situ Polymer Gels for Sealing Operation in Wellbore and Near-Well Zone

Kang,

Liu,

Jia

et al. 2024

Energy Fuels

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In situ polymer gels have been received as a useful tool for sealing operations such as fluid loss control during well drilling and workover and completion, well stimulation, water shutoff, wellbore integrity, and wellbore pressure management. With the development of deep-sea, deep-earth, and unconventional reservoirs, various harsh conditions such as high temperature, high pressure, and complex working conditions pose great challenges to the performance of gels. This paper first summarizes the application and operating mechanism of in situ polymer gels for sealing operations in wellbore and near-wellbore zones. Then, the in situ polymer gels are categorized into three types, in situ monomer gels, in situ cross-linked gels, and in situ generated foam gels, and the advantages and disadvantages of these three types of gels are introduced. Second, an overview of performance improvement methods for in situ polymer gels is highlighted, including improved temperature resistance and strength, accelerated gelation, retarded gelation, gel-breaking methods, and self-degradation systems. Finally, the challenges and prospects of in situ polymer gels for sealing operation in wellbores and near-well zones are presented, to provide references for the application, formulation, and performance improvement of in situ polymer gels.

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“…The key parameters of gel flooding are the gelation time, adsorption quantity, viscosity, breakthrough pressure, and the RF and RRF of the gel. Many researchers have investigated these key parameters using experiments and obtained good results [ 21 , 22 , 23 , 24 , 25 , 26 , 27 , 28 ]. Zhang et al [ 21 ] found that higher 2-acrylamido-2-methylpropane sulfonic acid content resulted in a higher gelation time for three gel systems prepared with S00, S30, and S50 polymers.…”

Section: Introductionmentioning

confidence: 99%

“…Many researchers have investigated these key parameters using experiments and obtained good results [ 21 , 22 , 23 , 24 , 25 , 26 , 27 , 28 ]. Zhang et al [ 21 ] found that higher 2-acrylamido-2-methylpropane sulfonic acid content resulted in a higher gelation time for three gel systems prepared with S00, S30, and S50 polymers. Li et al [ 22 ] discovered that the gelation time of a sustained-release crosslinker/water-soluble thixotropic polymer gel system decreased with the increase in poly (ethyleneimine) concentration.…”

Section: Introductionmentioning

confidence: 99%

Optimization of Gel Flooding during the High Water Cut Stage in a Conglomerate Reservoir of the Xinjiang A Oilfield

Xin

Liu

et al. 2023

Polymers

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Influenced by water injection, a dominant flow channel is easily formed in the high water cut stage of a conglomerate reservoir, resulting in the inefficient or ineffective circulation of the injected water. With gel flooding as one of the effective development methods to solve the above problems, its parameter optimization determines its final development effect, which still faces great challenges. A new optimization method for gel flooding is proposed in this paper. Firstly, the gel flooding parameters were obtained through physical experiments; then, an experimental model of gel flooding was established according to the target reservoir, and parameter sensitivity analysis was carried out. Next, a history matching of the gel flooding experiment was carried out. Finally, history matching of the target reservoir was also carried out, and a gel flooding scheme was designed and optimized to determine the best parameters. The experimental results showed that the gelation time was 4 h and the gel viscosity was 6332 mPa·s; the breakthrough pressure, resistance factor (RF), and residual resistance factor (RRF) all decreased with the increase in permeability. The gel had a good profile control ability and improved oil recovery by 16.40%. The numerical simulation results illustrated that the porosity of the high permeability layer (HPL) had the greatest impact on the cumulative oil production (COP) of the HPL, and the maximum polymer adsorption value of the HPL had the largest influence on the COP of the low permeability layer (LPL) and the water cut of both layers. Benefiting from parameter sensitivity analysis, history matching of the gel flooding experiment and a conglomerate reservoir in the Xinjiang A Oilfield with less time consumed and good quality was obtained. The optimization results of gel flooding during the high water cut stage in a conglomerate reservoir of the Xinjiang A Oilfield were as follows: the gel injection volume, injection rate, and polymer concentration were 2000 m3, 50 m3/d, and 2500 mg/L, respectively. It was predicted that the water cut would decrease by 6.90% and the oil recovery would increase by 2.44% in two years. This paper not only provides a more scientific and efficient optimization method for gel flooding in conglomerate reservoirs but also has important significance for improving the oil recovery of conglomerate reservoirs.

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Effect of AMPS(2-acrylamido-2-methylpropane sulfonic acid) content on the properties of polymer gels

Cited by 23 publications

References 22 publications

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

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

Progress and Prospects of In Situ Polymer Gels for Sealing Operation in Wellbore and Near-Well Zone

Optimization of Gel Flooding during the High Water Cut Stage in a Conglomerate Reservoir of the Xinjiang A Oilfield

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