Laboratory measurement of water imbibition into low-permeability welded tuff

Hu, Qinhong; Persoff, Peter; Wang, Joe S.Y

doi:10.1016/s0022-1694(00)00388-7

Cited by 62 publications

(41 citation statements)

References 8 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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“…Because of the mathematical analogy between diffusion and imbibition, liquid imbibition can be used to probe a rock's pore connectivity . Imbibition tests, which are much faster than diffusion tests, involve exposing one face of a rock sample to liquid (for example, water, API brine or n-decane), and monitoring the fluid mass uptake over time (e.g., Hu et al 2001;Schembre and Kovscek 2006). Using the network modeling results of Ewing and Horton (2002), we can probe pore connectivity, as indicated by the slope of log (imbibed liquid mass) versus log (time).…”

Section: Spontaneous Fluid Imbibition and Tracer Migrationmentioning

confidence: 99%

“…The experimental procedure and data processing of imbibition tests were described in detail by Hu et al (2001). Samples were first oven-dried at 60°C for at least 48 h, in order to achieve a constant initial water saturation state, before being subjected to the imbibition experiments.…”

Section: Spontaneous Fluid Imbibition and Tracer Migrationmentioning

confidence: 99%

Pore structure and tracer migration behavior of typical American and Chinese shales

Liu

Gao

et al. 2015

Pet. Sci.

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With estimated shale gas resources greater than those of US and Canada combined, China has been embarking on an ambitious shale development program. However, nearly 30 years of American experience in shale hydrocarbon exploration and production indicates a low total recovery of shale gas at 12 %-30 % and tight oil at 5 %-10 %. One of the main barriers to sustainable development of shale resources, namely the pore structure (geometry and connectivity) of the nanopores for storing and transporting hydrocarbons, is rarely investigated. In this study, we collected samples from a variety of leading hydrocarbon-producing shale formations in US and China. These formations have different ages and geologic characteristics (e.g., porosity, permeability, mineralogy, total organic content, and thermal maturation). We studied their pore structure characteristics, imbibition and saturated diffusion, edge-accessible porosity, and wettability with four complementary tests: mercury intrusion porosimetry, fluid and tracer imbibition into initially dry shale, tracer diffusion into fluid-saturated shale, and high-pressure Wood's metal intrusion followed with imaging and elemental mapping. The imbibition and diffusion tests use tracer-bearing wettability fluids (API brine or n-decane) to examine the association of tracers with mineral or organic matter phases, using a sensitive and micro-scale elemental laser ablation ICP-MS mapping technique. For two molecular tracers in n-decane fluid with the estimated sizes of 1.39 nm 9 0.29 nm 9 0.18 nm for 1-iododecane and 1.27 nm 9 0.92 nm 9 0.78 nm for trichlorooxobis (triphenylphosphine) rhenium, much less penetration was observed for larger molecules of organic rhenium in shales with median pore-throat sizes of several nanometers. This indicates the probable entanglement of sub-nano-sized molecules in shales with nano-sized pore-throats. Overall findings from the above innovative approaches indicate the limited accessibility (several millimeters from sample edge) and connectivity of tortuous nanopore spaces in shales with spatial wettability, which could lead to the low overall hydrocarbon recovery because of the limited fracture-matrix connection and migration of hydrocarbon molecules from the shale matrix to the stimulated fracture network.

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“…It is well known that sorptivity has the capacity to quantify the rate of water imbibition in porous media, which is controlled by both the capillary pressure and permeability of the porous media (Philip, 1957;Humphrey et al, 1996;Hu et al, 2001). The sorptivity is a very useful index for characterizing water transient imbibition process.…”

Section: Quantification Of Gaseous and Adsorbed Methane Behaviormentioning

confidence: 99%

Influence of water invasion on methane adsorption behavior in coal

Wang

Sui

Tang

et al. 2018

International Journal of Coal Geology

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Highlights:Experiments evidence that bulk water invasion displaces adsorbed methane in coal. The displace efficiency depends on equilibrium pressure and invasion water content. The displacement effects can be attributed to capillary effects and preferential flow. This work provides insights for coal seam gas drainage design using water invasion. Abstract:Fluid displacement is the fundamental process for subsurface fossil fuels extraction. Water invasion in coal seams is one of the routinely used stimulation approaches for coal seam methane extraction in underground coal mines. However, how the invading bulk water interacts with adsorbed/gaseous methane in coal is rarely considered even though it is known that moisture presence in coal decreases methane uptake by occupying adsorption sites. Here we study how the invading water interacts with adsorbed/gaseous methane in molded coal under elevated pressures using a custom-designed instrument; the test procedure mimics the real water invasion process in engineering applications. Experimental results demonstrate that invasion water displaces adsorbed methane in nanopores of coal and thus enhances the free gas content. The displacement mechanism can be attributed to capillary effect and preferential flow in a coating mode. It was found that Philip's sorptivity model can simulate the relationship between displaced methane content and time, and the obtained sorptivity increases with increasing water invasion content and is independent of gas pressure. It was observed that the higher the initial adsorption equilibrium pressure, the larger the displaced methane content, and this can be attributed to the pressure-dependent feature of adsorbed methane density. The higher the invasion water content, the higher the displaced methane content. These experimental results are also applied for optimizing gas drainage borehole arrangement to efficiently drain coal seam gas in underground coal mines. These findings provide a new perspective to understand the interactions between bulk water and methane in coals and pave the way for developing new technologies for methane recovery in coal seams.

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Laboratory measurement of water imbibition into low-permeability welded tuff

Cited by 62 publications

References 8 publications

Low nanopore connectivity limits gas production in Barnett formation

Low nanopore connectivity limits gas production in Barnett formation

Pore structure and tracer migration behavior of typical American and Chinese shales

Influence of water invasion on methane adsorption behavior in coal

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