Recuperação avançada de óleo viscoso por injeção de polímero em diferentes temperaturas

Abstract

A well-designed polymer flooding can be one of the most efficient and low-cost improved oil recovery methods, among the chemical ones. The anticipation in the oil production and the improvement in the management of the injected and produced fluid are the main advantages of this method. However, polymer solutions are often injected into complex reservoirs with high levels of salinity, hardness and temperature. Hence, before to the implementation of this recovery method, a previous study is necessary to evaluate the influence of these factors on polymer solutions and their effect on oil recovery efficiency. This study aims to assess the effectiveness of the injection of partially hydrolyzed polyacrylamide (HPAM) polymer solutions, prepared in high salinity medium for recovery viscous oil at different temperatures. The experimental study involved three immiscible displacement tests conducted at 26°C, 50°C and 75 °C, using high permeability sandstone samples from Botucatu Formation. Mineral oil Lubrax SAE 15W-40 (≅180 cps @ 26 °C) and mineral oil Lubrax Gear MO 3200 (≅11000 cP @ 26 °C) were used to simulate the oil contained in the reservoir. Furthermore, a target oil viscosity of approximately 180 cP was proposed to maintain maximum similarity between the offset tests. Therefore, MO 3200 Lubrax Gear oil was diluted with kerosene at a ratio of 15% to 5% by volume to perform the tests at 50°C and 75 °C, respectively. On the other hand, the Lubrax SAE 15W-40 oil was used in the test at 26 °C without dilution. The simulation of the exploitation of the oil by conventional water flooding was carried out with a brine of sodium chloride at a concentration of 110000 ppm, without control of its viscosity in different tests. An extensive study of rheological characterization was carried out aiming at to select the polymer solution and simulate the enhanced recovery. Eleven solutions with different concentrations of HPAM, were prepared in saline solution (110000 ppm). Therefore, in this step, the effect of shear rate, temperature and concentration of the polymer over the apparent viscosity of the solutions can be evaluated. Based on the generated rheograms, three polymer solutions showing a viscosity of approximately 10 cP (@ 7,848 s-1) were selected. Thus, the effect of different temperature levels over the oil recovery factor (FR), the cumulative water-oil ratio (RAO), the fractionalflow curves and the relative permeability curves can be evaluated. The test results showed that the rise in temperature has a large effect on oil recovery, for both water injection and polymer injection. As temperature increases, there is a considerable rise in the oil recovery factor. For the different temperatures used in the experiments, there was obtained an increase of at least 10% in the FR.

Avaliação de bancos de gradação viscosa na injeção de polímeros para a recuperação de óleo pesado

“…Após o sistema atingir o equilíbrio, a solução salina é injetada na amostra sob da permeabilidade absoluta quando medido pela água pode estar associado ao arraste de finos, os quais podem eventualmente bloquear alguns poros do meio poroso induzindo a maiores diferenciais de pressão. Esse fenômeno também foi observado no trabalho de BENTO (2015).…”

“…Conforme pode ser visto na Figura 4.13, o formato das curvas de permeabilidade relativa indica que as amostras utilizadas nos testes de deslocamento caracterizam-se por serem respectivamente. Assim, ao final da segunda drenagem buscava-se produzir toda a água móvel presente na amostra, provinda da segunda embebição, mantendo-se apenas a água irredutível da primeira drenagem (BENTO, 2015). Por mais que a segunda drenagem se estenda por longos períodos de tempo até atingir a saturação de água conata, essa pode se distinguir daquela alcançada pela primeira drenagem devido a um processo de histerese.…”