Creation of Insitu EOR Foams by the Injection of Surfactant in Gas Dispersions - Lab Confirmation and Field Application

Ocampo, Alonso; Restrepo, Alejandro; Lopera, Sergio H.; Mejía, Juan M.

doi:10.2118/190219-ms

Cited by 12 publications

(3 citation statements)

References 12 publications

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“…Displacement tests were performed in a linear flow regime at a liquid flow rate of 0.5 cm 3 ·s –1 and a gas flow of 1000 cm 3 . , A synthetic brine (2% KCl, viscosity of 1.0 cP at 80 °C), the light crude oil (43° API, viscosity of 1.5 cP at 80 °C), and flue gas (84% N 2 and 16% CO 2 ) were used. The overburden pressure was 450 bar, the pore pressure was 276 bar, and the temperature was 80 °C.…”

Section: Methodsmentioning

confidence: 99%

Injection of Nanofluids with Fluorosurfactant-Modified Nanoparticles Dispersed in a Flue Gas Stream at Very Low Concentration for Enhanced Oil Recovery (EOR) in Tight Gas–Condensate Reservoirs

et al. 2020

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The main objective of this work is to evaluate the effect of nanofluids formed by surface-modified nanoparticles with a fluorosurfactant dispersed in a flue gas stream at low concentrations as an enhanced oil recovery (EOR) process applied to a tight gas−condensate reservoirs (TGCR). This research is a continuation of our previous study (doi.org/10.1021/acsami.9b22383) in which nanoparticles of γ-Al 2 O 3 and MgO modified with a short-chain fluorinated anionic surfactant (SY) at 30% by weight were developed. Here, the nanomaterials were used for preparing nanofluids (NF) at different concentrations to improve the mobility of the liquids in TGCR. Contact angle tests under high-pressure and high-temperature (HPHT) conditions were performed from 5 to 276 bar and at a constant temperature of 80 °C through the sessile drop technique to select the best nanofluid that generates a gaswettability for EOR operations. Interfacial tension (IFT) measurements at high pressure (276 bar) and high temperature (80 °C) were also conducted to determine the selectivity of nanofluids to locate at the rock−fluid interface. The nanoparticles with superior performance were further evaluated through coreflooding tests at reservoir conditions of overburden pressure of 448 bar, pore pressure of 276 bar, and a temperature of 80 °C in a tight sandstone outcrop. The best results found for the contact angle and IFT at HPHT were obtained for the nanofluid of γ-alumina nanoparticles functionalized with fluorosurfactant at 30% by weight (AlSY30) dispersed in water at a concentration of 300 mg•L −1 (AlSY30-NF). The contact angle results obtained at reservoir conditions at 276 bar and 80 °C were 122 ± 2°and 119 ± 1°for water and oil, respectively. Also, IFT tests showed the preference of these nanofluids to be located at the rock−fluid interface and thus generate greater performance from the injected treatments to modify the rock wettability. These results are supported by a more than 95% increase in the energy binding to the oil/brine (ΔE) interface of AlSY30 nanoparticles than MgSY30 nanoparticles. A novel coreflooding test was performed by dispersing the nanofluid at different concentrations (from 0 to 300 mg•L −1 ) in a flue gas stream. A low concentration of 10 mg•L −1 resulted in a residual oil saturation (Sor) reduction of 57% and an increase in oil recovery of approximately 23% relative to the flue gas in the absence of nanofluid. A synergistic effect between a wettability alteration and a decrease in IFT occurred due to nanofluid dispersal in the flue gas stream. The results obtained in this study are expected to promote innovative and efficient technology for dispersed nanofluid injection as a recovery method in tightly condensed gas fields with excellent performance at low concentrations.

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Section: Methodsmentioning

confidence: 99%

Injection of Nanofluids with Fluorosurfactant-Modified Nanoparticles Dispersed in a Flue Gas Stream at Very Low Concentration for Enhanced Oil Recovery (EOR) in Tight Gas–Condensate Reservoirs

et al. 2020

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“…Surfactant-alternating gas (SAG) combined with foams dispersed in gas injections leads to an increased treatment depth than SAG alone, and the foams block high-permeability fractures. This process increases the potential of inaccessible fractures until then [13][14][15]. Hence, implementing a proper process requires extensive laboratory work and simulation studies to be effective.…”

Section: Introductionmentioning

confidence: 99%

Evaluation of Gas-Based EOR Methods in Gas-Invaded Zones of Fractured Carbonate Reservoir

et al. 2022

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More than half of all recoverable oil reserves are found in carbonate rocks. Most of these fields are highly fractured and develop different zonations during primary and secondary recovery stages; therefore, they require a different developmental approach than conventional reservoirs. Experimental results for water-alternating gas injection [WAG] and foam-assisted water-alternating gas [FAWAG] injection under secondary and tertiary recovery conditions were used to investigate these enhanced oil recovery [EOR] methods in gas-invaded reservoirs. The relative permeability curves of the cores and the fitting foam parameters were derived from these experiments through history matching. These findings were then used in a quarter five-spot, cross-sectional, and a sector model of a carbonate reservoir where a double five-spot setup was implemented. The fracture and matrix properties’ impact on the recovery was illustrated through the cross-sectional model. The gas mobility reduction effect of the FAWAG was more noticeable than that of WAG. The apparent viscosity of the gas was increased due to the foam presence, which caused a diversion of the gas from the fractures into the matrix blocks. This greatly enhanced the sweep efficiency and led to higher oil recovery. The gas front was much sharper, and gravity overrides by the gas were much less of a concern. The properties of the fracture network also had a significant effect on the recovery. Oil recovery was found to be most sensitive to fracture permeability. At the same time, sweep efficiency increased substantially, improving the recovery rate in the early injection stages, and differed slightly at the ultimate recovery. However, a lower fracture permeability facilitated gas entry into the matrix blocks. The results of the reservoir sector model were similar to the core and pilot. However, the WAG injection recovered more of the uppermost layers, whereas significant portions of the lowest layer were not effectively recovered. In contrast, FAWAG was more effective in the lowest layer of the reservoir. The FAWAG was a beneficial aid in the recovery of gas-invaded fractured reservoirs, increasing the oil recovery factor with respect to WAG.

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“…Foam has been applied for gas shutoff in production wells, and as a mobility control agent especially in gas injection of WAG (water alternating gas) operations where early gas breakthrough may occur. Recent field experiences (Blaker et al 2002;Skoreyko et al 2011;Ocampo-Florez et al 2014;Ocampo et al 2018) have proved that foam improves sweep efficiency and can divert injected gas. In addition, foam may increase the oil plateau period for mature oil fields by reducing the gas/oil ratio for wells suffering from high gas production.…”

Section: Introductionmentioning

confidence: 99%

Foam Generation, Propagation and Stability in Porous Medium

et al. 2019

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There have been several foam field applications in recent years. Foam treatments targeting gas mobility control in injectors as well as gas blocking in production wells have been performed without causing operational problems. The most widely used injection strategy of foam has been injecting alternating slugs of surfactant in brine with gas injection. This procedure seems to be beneficial as injection is easy to perform and control below fracturing pressure. Simultaneous injection of surfactant solution and gas may give difficulties, especially with interpretation of the tests, if fracturing pressure are exceeded during the injection period. This paper reviews critical aspects of foam for reservoir applications and intends to motivate for further field trials. Key parameters for qualification of foam are: foam generation, propagation in porous medium, foam strength and stability of foam. Stability is discussed, especially in the presence of oil at reservoir conditions. Data on each of these topics are included, as well as extracted summary of relevant literature. Experimental studies have shown that foam is generated at low surfactant concentration even below the CMC (critical micelle concentration). Results indicate that in situ foam generation in porous medium may depend on available nucleation sites. In situ generation of foam is complex and has been found to be especially difficult in oil wet carbonate rocks. Foam propagation in porous medium has been summarized, and propagation rate for a given experiment seems to be constant with time and distance. Laboratory studies confirm a propagation rate of 1-3 m/day. Field tests performed have not given reliable information of foam propagation rate, and future field pilots are encouraged to include observation wells in order to gain information of field-scale foam propagation. Foam strength is generally high with all gases. The exception is CO 2 at high pressure where CO 2 becomes supercritical. Stability of foam has been studied in laboratory and field tests, and has confirmed long-term stability of foam.

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Creation of Insitu EOR Foams by the Injection of Surfactant in Gas Dispersions - Lab Confirmation and Field Application

Cited by 12 publications

References 12 publications

Injection of Nanofluids with Fluorosurfactant-Modified Nanoparticles Dispersed in a Flue Gas Stream at Very Low Concentration for Enhanced Oil Recovery (EOR) in Tight Gas–Condensate Reservoirs

Injection of Nanofluids with Fluorosurfactant-Modified Nanoparticles Dispersed in a Flue Gas Stream at Very Low Concentration for Enhanced Oil Recovery (EOR) in Tight Gas–Condensate Reservoirs

Evaluation of Gas-Based EOR Methods in Gas-Invaded Zones of Fractured Carbonate Reservoir

Foam Generation, Propagation and Stability in Porous Medium

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