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Abstract Organic scale and poor wettability can significantly limit the productivity of un/conventional wells. Traditional treatment methods including organic solvents and hot oiling are hazardous and need to be performed regularly because the deposits are either not fully removed or further deposition recreates the damage. This paper describes the learnings and production results of implementing a tailored nanoparticle-based fluid or "nanofluid" in at least 24 wells across different US basins to remediate paraffin/asphaltene issues and to modify wettability.
Several horizontal and vertical wells across 7 geological basins experienced low productivity and high decline rates, attributed to organic deposition around perforations and poor wettability in near-wellbore regions. A newly developed water-based fluid containing dispersed metal-oxide nanoparticles remediated these organic deposits through a unique mechanism of structural disjoining pressure or "uplift pressure." The fluids were tailored based on the crude oil and water compositions. The nanoparticles function as disjoining agents to disperse large organic molecules and prevent immediate re-coagulation. Depending on the matrix properties a degree of inhibition is also expected since the nanoparticles could create a layer on the rock surface, altering the surface characteristics such as wettability.
Prior to field pilots, corefloods were conducted where heptane was injected into an oil-saturated rock to simulate asphaltene damage. Permeability measurements and SEM imaging helped in analyzing productivity improvements and mechanism of nanoparticles to disperse the organic deposits.
In the field, the nanoparticle-based fluid was bullheaded with water at a predefined concentration and allowed to soak for 1-2 days in wells that were on different artificial lift systems such as socker rod pump, plunger, and gas lifts. The fluid can be pumped with acid as well. The volumes of the nanoparticle-based fluid injected ranged from 700 to 1,500 gallons per well. In certain jobs, packers were used to spot treat damaged zones with vertical depths of 3,000 – 13,000 ft. These treatments were conducted at wellbore temperatures of 65-212°F and crude oil APIs of 19–46°. After the treatment, the fluids were produced back with the regular production stream, making this implementation very simple, cost-effective, non-toxic, and universally applicable.
Coreflood testing demonstrated permeability recovery post-treatment and showed improved relative permeability to oil due to wettability alteration, leading to higher oil cut. The field case studies indicated long-term improvement in hydrocarbon production volumes with lower decline rates. In some cases, hydrocarbon production showed better returns for a period of 24 months compared to pre-treatment decline curves. In a Deep Basin well, the IP60 data showed an average increase in production of about 40%. A well in the Williston Basin, recovered an additional 30,000 bbls of oil over 18 months post-treatment. Additionally, the average water cut decreased in these wells indicating an effective wettability alteration.
This new tailored technology yielded a simple, novel, long-term, non-hazardous, and universally applicable treatment method with effective deposit dispersion and rock treatment to improve wettability and inhibit organic damage.
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