Modeling the Impact of Capillary Pressure Reduction by Surfactants

Gdanski, Rick

doi:10.2118/106062-ms

Cited by 18 publications

(1 citation statement)

References 11 publications

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“…As was written by Penny et al (2005), this reduces the energy required to produce back the injected fluid and allows for cleaner pore throats and increased relative permeability to gas. Gdanski (2007) agrees with this, though he states that some of the negative effects of water saturation, specifically high capillary pressures, often become negligible in permeabilities of 1 mD or more. This is validated in work conducted by Howard et al (2009) where retained permeability of cores greater than 1mD showed no benefit from surfactant or microemulsion usage.…”

Section: Introductionmentioning

confidence: 82%

Post-Fracturing Fluid-Recovery Enhancement With Microemulsion

Agee

Wirajati

Schafer

et al. 2010

SPE International Symposium and Exhibition on Formation Damage Control

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The fields of East Kalimantan, Indonesia contain several depleted gas zones of medium permeability (0.1 to 300 mD). Though the permeability is quite good for gas bearing formations, the majority of the wells targeting these sands have failed to produce at expected rates. In the 1980s, hydraulic fracturing was introduced to the area in an attempt to increase production. The treatments yielded limited success with many wells actually producing less after being fractured. This led operators in the area to believe that the formations could be water sensitive with damage from the injected fluids causing the poor results after fracturing. As laboratory testing has ruled out water-sensitive mineralogy, the suspected cause of damage has been attributed to a decrease in relative permeability to gas after the fracturing fluid has penetrated the pore throats (water block). The water block conclusion is supported by the low percentage of injected fluids that are returned after the treatment.In 2007, VICO performed four fracturing treatments using a conventional surfactant to aid in post-frac cleanup. Only 2 of the 4 wells that were fractured produced after the treatment. Again, a common problem between the wells was the poor return of treatment fluids during cleanout. The limited success of these treatments indicated the water block issue had not been resolved. After reviewing the results of the first four wells, three additional fracturing treatments were placed in similar reservoirs using a microemulsion additive instead of the surfactant. Though laboratory testing in cores between 1 and 8.5mD failed to show a significant difference between the microemulsion and surfactant, the wells fractured with the microemulsion additive consistently outperformed those fractured previously in terms of returned treatment fluids and incremental production. Paktinat et al. (2006) wrote that the use of fracturing fluids with microemulsion in unconventional tight gas reservoirs can help increase production by increasing the relative permeability to gas in the area surrounding the fracture. Our study shows that similar benefits can also be achieved in depleted gas reservoirs with permeabilities greater than 1 mD, even if the benefits can not be clearly demonstrated under laboratory conditions.

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Section: Introductionmentioning

confidence: 82%

Post-Fracturing Fluid-Recovery Enhancement With Microemulsion

Agee

Wirajati

Schafer

et al. 2010

SPE International Symposium and Exhibition on Formation Damage Control

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Scale Inhibitor Squeeze Treatments

Vazquez

2023

Modelling Oilfield Scale Squeeze Treatments

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Surfactants are Ineffective for Reducing Imbibition of Water-Based Fracturing Fluids in Deep Gas Reservoirs

2021

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Minimizing loss of injected hydraulic fracturing fluids into shale along fracturematrix boundaries is desired because imbibed water restricts gas production and wastes valuable water resources. This problem has motivated the addition of surfactants into water-based hydraulic fracturing fluids in order to reduce the capillary driving force for imbibition. Here, we show that reduction in interfacial tension and wettability alteration have negligible ability to reduce imbibition in deep gas reservoirs. The effectiveness of altering capillary forces acting at the wetting front also depends on the injection pressure acting at the fracture-matrix boundary.The pressure at the interface between the fracture and the shale matrix is constrained between the reservoir pore pressure and formation pressure (rock fracture pressure, also known as breakdown pressure of the rock) and increases with depth to magnitudes that greatly exceed that of capillary pressures. The analyses presented here show that even maximum alteration of interfacial properties that result in strongly hydrophobic interactions between the fracturing fluid and reservoir rock is incapable of significantly reducing imbibition in deep reservoirs. Instead of using surfactants, this analysis points to decreases in wellbore shut-in pressures and shut-in times as practical options for reducing imbibition losses of water-based fluids.

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Modeling the Impact of Capillary Pressure Reduction by Surfactants

Cited by 18 publications

References 11 publications

Post-Fracturing Fluid-Recovery Enhancement With Microemulsion

Post-Fracturing Fluid-Recovery Enhancement With Microemulsion

Scale Inhibitor Squeeze Treatments

Surfactants are Ineffective for Reducing Imbibition of Water-Based Fracturing Fluids in Deep Gas Reservoirs

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