Case Histories: Damage Prevention by Leakoff Control and Cleanup of Fracturing Fluids in Appalachian Gas Reservoirs

Paktinat, Javad; Williams, Curtis; Pinkhouse, Joseph; Clark, G. A.; Penny, Glenn S.

doi:10.2118/98145-ms

Cited by 20 publications

(5 citation statements)

References 12 publications

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“…The use of microemulsions in improving production from resource shale has been documented in numerous studies [1][2][3][4][5][6]. These studies have demonstrated that microemulsions in the form of complex nanofluids have the potential to restore the effective permeability of the rock, hence, promoting the fluid flow-back from the reservoir during production.…”

Section: Introductionmentioning

confidence: 99%

Insights into Mobilization of Shale Oil using Microemulsion

Bui¹,

Akkutlu²,

Zelenev³

et al. 2015

Unconventional Resources Technology Conference

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Molecular dynamics simulation is employed to investigate the nature of two-phase (oil-water) flow in organic capillaries. The capillary wall is modeled using graphite to represent kerogen pores in liquid-rich resource shale. We consider that the water carries a nonionic surfactant and a solubilized terpene solvent in the form of a microemulsion, and that it has previously been introduced to the capillary during hydraulic fracturing operation. The water has already displaced a portion of the oil in-place mechanically and now occupies the central part of the capillary. The residual oil, on the other hand, stays by the capillary walls as a stagnant film.Equilibrium simulations show that, under the influence of organic walls, the solvent inside the microemulsion droplets enables not only the surfactant but also the complete droplet to adsorb to the interfaces. Hence, delivering the surfactant molecules to the oil-water interface is achieved faster and more effectively in the organic capillaries. Once the droplet arrives at the interface, the droplet breaks down, the solvent dissolves into the oil film and diffuses. This process is similar to drug delivery at nano-scale.Using non-equilibrium simulations based on the external force field approach we numerically performed steady-state flow measurements to establish that the solvent and the surfactant molecules play separate roles that are both essential in mobilizing the oil film. The surfactant deposited at the oil-water interface reduces the surface tension and acts as a linker that diminishes the slip at the interface. Hence, it effectively enables momentum transfer from the mobile water phase to the stagnant oil film. The solvent penetrating the oil film, on the other hand, modifies flow properties of the oil. In addition, due to selective adsorption, the solvent displaces the adsorbed oil molecules and transforms that portion of the oil into the free oil phase. Consequently, the fractional flow of oil is additionally increased in the presence of solvent. The results of this work are important for understanding the effect of the microemulsion on flow in organic capillaries and its effect on shale oil recovery.

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Section: Introductionmentioning

confidence: 99%

Insights into Mobilization of Shale Oil using Microemulsion

Bui¹,

Akkutlu²,

Zelenev³

et al. 2015

Unconventional Resources Technology Conference

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“…Al-Anazi et al (2007) performed the analysis of the treated cores using an environmental scanning electron microscope (ESEM) and gave an evidence of wettability alteration at the pore scale. Paktinat et al (2006) demonstrated that the use of microemulsion fluids in hydraulic fracturing gives higher water recovery when compared with conventional surfactant treatments. The oil-inwater microemulsion, composed of oil inside swollen micelles in aqueous solutions, are characterized by drop sizes of 10-20 nm and ultra low oil-water interfacial tensions of 10 −3 to 10 −6 mN/m.…”

Section: Introductionmentioning

confidence: 99%

Permanent Alteration of Porous Media Wettability from Liquid-Wetting to Intermediate Gas-Wetting

Firoozabadi

2010

Transp Porous Med

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Wettability of Berea and low permeability reservoir rocks are permanently altered from liquid-wetting to intermediate gas-wetting. We use water and decane as model liquid, and air and nitrogen as model gas in the experiments. New chemicals with various functional groups are used in the wettability alteration. We perform compositional analyses of the treated chemical solutions extracted from rock treatment by gas chromatography-mass spectrometry (GCMS) and by inductively coupled plasma-mass spectrometry (ICPMS). The analyses demonstrate reaction between the chemicals and the rock substrate. There is no measurable change in permeability from the chemical reaction for the low molecular weight chemicals. The results reveal the permanent alteration of wettability. Tests are conducted to measure contact angle, spontaneous imbibition, and flow to assess the effect of wettability alteration on flow performance as a function of chemical concentration and functionality. For Berea, the contact angle for the water-air-rock is altered from 0 • to ∼150 • depending on the chemical concentration. For the reservoir rock, the contact angle is altered from ∼70 • to ∼130 • . As a result of the treatment, the water flow rate may increase two and a half times for a given pressure drop in the Berea. The permanent alteration of wettability with the new chemicals is intended for prevention of water blocking in gas production from tight reservoirs. Instead of hydraulic fracturing when water is introduced in formations with most of the water retained by the water-wet rocks, one may use the new chemical surfactants in fracturing to avoid water retention for high gas well productivity.

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“…Most wells are stimulated with water-based fracturing fluids and produce back less than half of the injected fluids, even with the use of conventional surfactants that lower the air-water interfacial tension (Paktinat et al 2006b). It must be assumed that these large quantities of fluid are trapped in the reservoir surrounding the wellbore and, in the case of hydraulic fracturing, the fluid is trapped in the area surrounding the fracture and within the fracture itself.…”

Section: Description Of Novel Me Surfactantmentioning

confidence: 99%

“…This is even more important in low-pressure areas where the available pressure may not overcome the capillary end effect, leaving fluid trapped in the reservoir in a manner as illustrated in Fig. 2 (Paktinat et al 2006b). Where: P c is capillary pressure, psi σ is surface tension, dynes/cm Sw is water saturation, fraction φ is porosity, fraction k is absolute permeability; md a1, a2, and a3 are adjustable constants…”

Section: Description Of Novel Me Surfactantmentioning

confidence: 99%

Improving Gas Production and Reducing Fracture Face Damage using a Microemulsion Surfactant—Field Trail in Burgos Basin, Mexico

et al. 2012

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Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage.Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico-located in the North-East area of the country and bordered with South Texas in the USA-problems still persist.This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension.This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.

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Case Histories: Damage Prevention by Leakoff Control and Cleanup of Fracturing Fluids in Appalachian Gas Reservoirs

Cited by 20 publications

References 12 publications

Insights into Mobilization of Shale Oil using Microemulsion

Insights into Mobilization of Shale Oil using Microemulsion

Permanent Alteration of Porous Media Wettability from Liquid-Wetting to Intermediate Gas-Wetting

Improving Gas Production and Reducing Fracture Face Damage using a Microemulsion Surfactant—Field Trail in Burgos Basin, Mexico

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