In this article,
we developed a new composite gel for plugging
dominant fluid flow channels in offshore oilfields. The composite
gel was synthesized by organic and inorganic gel networks interpenetrating
into a compact three-dimensional spatial network structure, resulting
in a good plugging effect. The performance of the composite gel was
evaluated from the aspects of gelling characteristics and gel microstructure,
while the plugging effect was evaluated through core experiments.
The results showed that the influencing order of each component on
gelling was acrylamide > cross-linking agent > urea > initiator
>
polyaluminum chloride. The initial viscosity of the composite gel
was about 5–6 mPa·s, and it had good plugging abilities
in different permeability cores. In comparison with inorganic gels
(plugging ratio of 77.2%) or organic gels (84.8%), the composite gel
system has a plugging ratio of up to 99.5% using a core with water
permeability of 4300 mD. Besides, the reservoir applicability of the
composite gel was studied, and the results suggested that the composite
gel system had good resistance to dilution, mechanical shear, oil
corrosion, and aging and could be quickly removed after plugging.
The reservoir heterogeneity of Q oilfield is more severe after long-term water injection development, and water flooding is ineffective. In this study, the combined technologies of profile control, profile control and flooding, and oil displacement were proposed to improve the water flooding development effect. Then, the influence of the well pattern type on the remaining oil distribution, after development, was investigated. Cr3+ polymer gel, which has an optimal gel-forming effect, was used as the profile control agent. Moreover, the entire molecular structure had a “network” structure. A polymer microsphere was used as a profile control and flooding agent, which showed a good hydration expansion capacity. The initial particle size distribution had a range of 7.2–11.1 μm, and the expansion multiple was 4.35–5.64 after 7 days. The surfactant was an oil displacement agent, and the interfacial tension was approximately 5.08–5.11 × 10−1 mN/m. After the “profile control + profile control and flooding + oil displacement” technologies, the horizontal well pattern had a large seepage area. The effect of expanding the sweep volume was significant, and the remaining oil saturation in each stage was lower than those of the vertical and horizontal–vertical combined well patterns. Compared with the first water flooding stage, the remaining oil saturation values of the three permeable layers changed by 11.9%, 17.3%, and 19.8% during the subsequent water flooding stage.
Polymer flooding and polymer/surfactant flooding have achieved good efficiency in the application of conventional reservoir, but the existed chemical flooding technology cannot cannot address the issues of the requirements of chemical flooding in high salinity reservoir. Under the condition of high salinity reservoir, due to the increase of calcium and magnesium ions, the increasing viscosity effect of oil displacement system is lost. In order to study the feasibility of applying nanomaterials in the field of enhanced oil recovery under the conditions of high salinity reservoir, develop a low-concentration and high-efficiency oil displacement system. EAPC solution has advantages in reducing interfacial tension, but its viscosity is not good. Therefore, hydrophobically modified silica nanoparticles (SiO2 NPs) were added to the carboxylic acid–type erucic acid amide propyl betaine (EAPC) solution. The interaction between EAPC and hydrophobic carbon chains led to the exposure of carboxyl groups, thus making the system more stable. The interfacial activity and zeta potential were studied, and the interaction mechanism between modified SiO2 NPs and EAPC was obtained. The results show that when the EAPC concentration is 0.3%, the apparent viscosity of the modified silica nanoparticles (SiO2 NPs) composite system can reach 40 mPa·s, and the oil-water interfacial tension can be reduced to 10-2 mN/m. The micro-visualization model and the simulated oil displacement experiment proved that the modified SiO2 NPs (0.3%)/EAPC (0.3%) composite system has a variety of oil displacement mechanisms. Under the simulated reservoir conditions (total salinity of 25000 mg/L, calcium and magnesium ion concentration of 500 mg/L, 70 °C), it is proved that the modified SiO2 NPs composite system had good viscoelasticity and improved oil washing efficiency. The oil displacement system has guiding significance for effectively enhancing the recovery of high salinity reservoir.
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