Abstract
Existing reducing agents for cross-linking polymers are expensive and toxic and mostly limited for water shut off applications. A gelation study was performed on a safer, cheaper, more soluble, and short-lived gel by cross-linking polyacrylamide and chromium as a cross-linking agent using a rheometer and bead-pack porous media. The effect of concentration of sodium thiosulfate as the reducing agent was investigated to determine conditions for optimum yield strength and the gelation time and behavior which has never been published before. For a fixed minimum concentration (for the gel to form) of polyacrylamide and sodium dichromate, the gel yield strength vs. sodium thiosulfate concentration showed a somewhat bell-shaped curve initially increasing, reaching a peak at 2000 ppm, and then starting to decrease. The gelation formed by sodium thiosulfate was comparatively weak and short lived as compared to the ones formed by other reducing agents. Gel started to form instantaneously, reached a peak in 2 h, began to decrease, and then stabilized at 40 cp. The mobility reduction trends were similar to the yield strength curve. The short-lived gel could be useful to improve the waterflood mobility ratio far away from the wellbore without compromising on ease of injectivity.
Highlights
The hydrocarbon reservoirs initially produce hydrocarbon due to their high pressure
One suggestion is that chromium serves as a crosslinker between the polyacrylamide molecules
Another idea is that chromium forms a stable dispersion in the polymer solution which results in a high viscosity liquid or gel (Prud et al 1983)
Summary
The hydrocarbon reservoirs initially produce hydrocarbon due to their high pressure. Up to 95% of the hydrocarbon could remain in the reservoir after remaining pressure is not enough to lift hydrocarbons to surface which could be thousands of feet above the reservoir.At this point, secondary techniques are employed such as water or gas injection into the reservoir. The hydrocarbon reservoirs initially produce hydrocarbon due to their high pressure. Up to 95% of the hydrocarbon could remain in the reservoir after remaining pressure is not enough to lift hydrocarbons to surface which could be thousands of feet above the reservoir. At this point, secondary techniques are employed such as water or gas injection into the reservoir. If conditions are favorable such as the viscosity of reservoir oil is similar to the viscosity of the injected fluid, and there are no high permeability streaks, 25–60% additional recovery could be obtained. Vertical sweep efficiencies are usually quite low due to adverse
Sign-in/Register to view highlights & summary Talk to us
Join us for a 30 min session where you can share your feedback and ask us any queries you have
Schedule a callMore From: Journal of Petroleum Exploration and Production Technology
Disclaimer: All third-party content on this website/platform is and will remain the property of their respective owners and is provided on "as is" basis without any warranties, express or implied. Use of third-party content does not indicate any affiliation, sponsorship with or endorsement by them. Any references to third-party content is to identify the corresponding services and shall be considered fair use under The CopyrightLaw.
