COVID-19 is an acute respiratory disease caused by SARS-CoV-2, which has high transmissibility. People infected with SARS-CoV-2 can develop symptoms including cough, fever, pneumonia and other complications, which in severe...

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Summary Preformed particle gels (PPGs) have been successfully applied to control conformance for mature oil fields because of their advantages over conventional in-situ gels. However, field applications have demonstrated that current particle gels cannot efficiently plug open fractures, fracture-like channels, or conduits that exist in many mature oil fields. The objective of this study is to systematically evaluate a new recrosslinkable-PPG (RPPG) product that can be used to efficiently control the conformance for abnormal features. The RPPG can swell to 38 times its initial volume, and the equilibrium swelling ratio is independent of the brine salinity. Temperature and the particle size showed a gradient effect on the swelling rate of the gel. Additionally, the particle gels can recrosslink to form a rubber-like bulky material in the large-opening features after placement that significantly enhances the plugging efficiency. We systematically evaluated the effect of temperature and RPPG swelling ratio on the recrosslinking time, the gel strength after crosslinking, and the gel thermostability. Coreflooding tests were run to test whether RPPG can significantly improve the fracture-plugging efficiency compared with a traditional PPG that cannot recrosslink after pumping. The RPPG can be customized for mature reservoirs with a temperature from 23 to 80°C with a controllable size from tens of nanometers to a few millimeters. The recrosslinking time can be controlled from 2 to 80 hours, depending on the swelling ratio and temperature. The gel elastic modulus after recrosslinking can achieve from 300 to 10 800 Pa, depending on the swelling ratio and the temperature. Coreflooding tests showed that the breakthrough pressure of the recrosslinked RPPG can reach up to 300 psi/ft for a fracture with a 0.2-cm aperture, which is more than five times higher than that of the conventional PPG.

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Summary With the demand for conformance control in carbon dioxide (CO2) flooding fields, hydrolyzed polyacrylamide-chromium [HPAM-Cr (III)] polymer gel has been applied in fields for CO2 conformance control. However, the field application results are mixed with success and failure. This paper is intended to understand the HPAM-Cr (III) polymer gel plugging performance in CO2 flooding reservoirs through laboratory experiments and numerical analysis. We conducted core flooding tests to understand how the cycles of CO2 and water affect the HPAM-Cr (III) polymer gel plugging efficiency to CO2 and water during a water-alternating-gas (WAG) process. Berea Sandstone cores with the permeability range of 107 to 1225 md were used to evaluate the plugging performance in terms of residual resistance factor and breakthrough pressure, which is the minimum pressure required for CO2 to enter the gel-treated cores.We compared the pressure gradient from the near-wellbore to far-field with the gel breakthrough pressure, from which we analyzed under which conditions the gel treatment could be more successful. Results show that HPAM-Cr (III) polymer gel has higher breakthrough pressure in the low-permeability cores. The polymer gel can reduce the permeability to water much more than that to CO2. The disproportionate permeability reduction performance was more prominent in low-permeability cores than in high-permeability cores. The gel resistance to both CO2 and brine significantly decreased in later cycles. In high-permeability cores, the gel resistance to CO2 became negligible only after two cycles of water and CO2 injection. Because of the significant reduction of pressure gradient from near-wellbore to far-field in a radial flow condition and the dependence of breakthrough pressure on permeability and polymer concentration, we examined hypothetical reservoirs with no fractures, in which impermeable barriers separated high- and low-permeability zones and in which the gel was only placed in the high-permeability zone. We considered two scenarios: CO2 breaking through the gel and no CO2 breakthrough. No breakthrough represents the best condition in which the gel has no direct contact and can be stable in reservoirs for long. In contrast, the breakthrough scenario will result in the gel’s significant degradation and dehydration resulting from CO2 flowing through the gel, which will cause the gel treatment to fail.