Spontaneous countercurrent imbibition and forced displacement characteristics of low-permeability, siliceous shale rocks

Takahashi, Satoru; Kovscek, A. R.

doi:10.1016/j.petrol.2010.01.003

Cited by 107 publications

(53 citation statements)

References 21 publications

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“…Imbibition tests, which are much faster than diffusion tests, involve exposing one face of a rock sample to liquid, and monitoring the mass uptake over time [e.g., Hu et al , ; Takahashi and Kovscek , ]. Using the network modeling results of Ewing and Horton [], we can probe pore connectivity, as indicated by the slope of log‐imbibed liquid mass versus log time [ Hu et al , ].…”

Section: Methodsmentioning

confidence: 99%

Low nanopore connectivity limits gas production in Barnett formation

2015

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Gas‐producing wells in the Barnett Formation show a steep decline from initial production rates, even within the first year, and only 12–30% of the estimated gas in place is recovered. The underlying causes of these production constraints are not well understood. The rate‐limiting step in gas production is likely diffusive transport from matrix storage to the stimulated fracture network. Transport through a porous material such as shale is controlled by both geometry (e.g., pore size distribution) and topology (e.g., pore connectivity). Through an integrated experimental and theoretical approach, this work finds that the Barnett Formation has sparsely connected pores. Evidence of low pore connectivity includes the sparse and heterogeneous presence of trace levels of diffusing solutes beyond a few millimeters from a sample edge, the anomalous behavior of spontaneous water imbibition, the steep decline in edge‐accessible porosity observed in tracer concentrations following vacuum saturation, the low (about 0.2–0.4% by volume) level presence of Wood's metal alloy when injected at 600 MPa pressure, and high tortuosity from mercury injection capillary pressure. Results are consistent with an interpretation of pore connectivity based on percolation theory. Low pore connectivity of shale matrix limits its mass transfer interaction with the stimulated fracture network from hydraulic fracturing and serves as an important underlying cause for steep declines in gas production rates and a low overall recovery rate.

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Section: Methodsmentioning

confidence: 99%

Low nanopore connectivity limits gas production in Barnett formation

2015

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“…Forced imbibition at the lab-scale has been studied in the past both theoretically and experimentally (e.g. Rangel-German andKovscek, 2002, Riaz et al, 2007;Takahashi and Kovscek, 2009). Pressure-controlled forced imbibition is achieved by injecting fluid into a sample under a confining pressure at a constant pressure higher than that of the sample,.…”

Section: Introductionmentioning

confidence: 99%

Forced and Spontaneous Imbibition Experiments for Quantifying Surfactant Efficiency in Tight Shales

Roychaudhuri

Tsotsis

et al. 2014

SPE Western North American and Rocky Mountain Joint Meeting

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Surfactants have been used extensively in well completion practices and have been shown to favorably alter the wettability of a formation from highly water-wet to intermediate-wet, resulting in increased water recovery and in a reduction of water blockage around the wellbore. Spontaneous imbibition and contact angle measurements are the most popular methods for studying the efficacy of a given surfactant. Forced imbibition experiments on fractured cores under confining pressure provide a more realistic representation of the actual formation settings, but have not been used extensively to measure the effect of surfactant solutions. They are commonly avoided due to their additional experimental complexity when compared to their spontaneous imbibition counterparts. The forced imbibition data reveal information about the porosity and provide an estimate of fluid flow values under different confining pressures of the micro-fracture network and the core matrix from the imbibition rate. Compined with the pure water invasion rates, forced imbibition experiments with surfactants reveal potential impacts that the surfactant may have on a given formation.In this work, 1 in by 1 in shale core plugs have been used to study the efficacy of a surfactant towards increased load recovery. Each core plug undergoes two forced imbibition experiments lasting 24 hr in succession: One experiment is carried out with pure water while the second experiment employs a surfactant solution. The permeability and porosity of the samples are measured before each experiment to be able to account for any changes to the cores as a result of the forced imbibition experiments. During forced imbibition, the fluid is injected at a pressure of 3500 psi. We observe an increase in water recovery of approximately 60% for a low (ppm-level) concentration of a surfactant solution. We argue that spontaneous and forced imbibition experiments provide more realistic observations of the capillary pressure effects at play than do contact angle measurements, and that they should be used together for direct quantification of surfactant efficacy in these tight porous materials under realistic reservoir conditions. IntroductionIn low permeability porous media like gas shales, more than 70% of injected water during fracturing is lost to the formation and hence water recovery during flowback is very low. In completion practices, surfactants are generally used along with the fracturing fluid to increase recovery of the injected water. Surfactants aid the water recovery through their ability to reduce surface and interfacial tension, and alter wettability.Typically, contact angle measurements and spontaneous imbibition experiments are used to characterize the efficacy of surfactants. These experiments form the basis of wettability studies on most formations (Morrow et al., 1994). In our previous work (Roychaudhuri et al., 2013), we have seen that the addition of surfactants shows a beneficial effect by substantially increasing both the static and dynamic contact angles of w...

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“…Kuila et al [29] found that water could be imbibed into almost all nanopores of shale. Later, some scholars [30][31][32][33][34] carried out experiments to study the imbibition displacement mechanism in shale oil reservoirs and analyzed its feasibility. They examined the effects of surfactant and pH value of suction liquid on spontaneous imbibition recovery.…”

Section: Introductionmentioning

confidence: 99%

Characterization of the Dynamic Imbibition Displacement Mechanism in Tight Sandstone Reservoirs Using the NMR Technique

et al. 2020

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An experimental technique is developed to investigate the dynamic imbibition displacement mechanism in tight sandstone formations of the Yanchang group of the Ordos basin. By combining the dynamic imbibition core flooding experiments and NMR technique, the effects of the injection volume and rate on displacement efficiency are investigated. Moreover, the displacement efficiency of dynamic imbibition is compared with that of static imbibition. This study gains insights into the micromechanisms of dynamic imbibition in tight sandstone formations. It is found that the relative displacement efficiency of dynamic imbibition increases with the increase of injection volume. But the increment amplitude decreases with the increase of injection volume. With the same injection volume, the core displacement efficiency of dynamic imbibition with high permeability is obviously improved. However, the core displacement efficiency decreases rapidly with the increase of injection volume. Optimal injection volumes are recommended for tight sandstone formations with different permeabilities. With the increase of the displacement rate, the core displacement efficiency of dynamic imbibition shows a trend of first rising and then declining. There exists an optimal displacement rate in dynamic imbibition displacement, and the optimal displacement rate almost linearly increases with the increase of core permeability. The static imbibition displacement efficiency increases with the increase of soaking time, but the increment amplitude slows down obviously. The displacement efficiency of static imbibition in small pores is higher than that of dynamic imbibition. The displacement efficiency of dynamic imbibition in large pores or microcracks is significantly higher than that of static imbibition. This study provides theoretical support for the optimization and improvement of the waterflooding recovery process in tight sandstone reservoirs.

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Spontaneous countercurrent imbibition and forced displacement characteristics of low-permeability, siliceous shale rocks

Cited by 107 publications

References 21 publications

Low nanopore connectivity limits gas production in Barnett formation

Low nanopore connectivity limits gas production in Barnett formation

Forced and Spontaneous Imbibition Experiments for Quantifying Surfactant Efficiency in Tight Shales

Characterization of the Dynamic Imbibition Displacement Mechanism in Tight Sandstone Reservoirs Using the NMR Technique

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