The flow of homogeneous fluids through porous media: analogies with other physical problems

Hydrocarbon production, gas recovery from shale, CO2 storage and water management have a common scientific underpinning: multiphase flow in porous media. This book provides a fundamental description of multiphase flow through porous rock, with emphasis on the understanding of displacement processes at the pore, or micron, scale. Fundamental equations and principal concepts using energy, momentum, and mass balance are developed, and the latest developments in high-resolution three-dimensional imaging and associated modelling are explored. The treatment is pedagogical, developing sound physical principles to predict flow and recovery through complex rock structures, while providing a review of the recent literature. This systematic approach makes it an excellent reference for those who are new to the field. Inspired by recent research, and based on courses taught to thousands of students and professionals from around the world, it provides the scientific background necessary for a quantitative assessment of multiphase subsurface flow processes, and is ideal for hydrology and environmental engineering students, as well as professionals in the hydrocarbon, water and carbon storage industries.

Multiphase Flow in Permeable Media: A Pore-Scale Perspective

An extensive laboratory program was conducted for the measurement of the interfacial tension between CO2 and water or brine covering the ranges of (2 to 27) MPa pressure, (20 to 125) °C temperature, and (0 to 334 010) mg·L−1 water salinity. The laboratory experiments were conducted using the pendant drop method combined with the solution of the Laplace equation for capillarity for the profile of the brine drop in the CO2−brine equilibrium environment. The analysis of the resulting set of 378 IFT measurements reveals that: (1) under conditions of constant temperature and water salinity, IFT steeply decreases with increasing pressure in the range P Pc with an asymptotic trend toward a constant value at higher pressures; (2) under the same conditions of constant pressure and temperature, IFT increases with increasing water salinity, reflecting decreasing CO2 solubility in brine as salinity increases; (3) the dependence of IFT on temperature is more complex than that on eithe...

Interfacial Tension between CO2, Freshwater, and Brine in the Range of Pressure from (2 to 27) MPa, Temperature from (20 to 125) °C, and Water Salinity from (0 to 334 000) mg·L−1

China produced 17.1 billion cubic meters (BCM) of methane sourced from coal seams in 2015, of which 4.43 BCM is from wells drilled from the surface. This level of production is a clear indicator th...

Resources and geology of coalbed methane in China: a review

Convective dissolution of CO2 in saline aquifers: Progress in modeling and experiments

Injecting pure N2 and CO2 to coal for enhanced coalbed methane: Experimental observations and numerical simulation

This article presents a numerical investigation of the combined effects of capil- lary pressure, salinity and in situ thermodynamic conditions on CO2-brine-rock interactions in a saline aquifer. We demonstrate that the interrelations between capillary pressure, salin- ity, dissolution and drying-out affect CO2 injectivity and storage capacity of a saline aquifer. High capillary forces require a high injection pressure for a given injection rate. Depending on salinity, the increase in injection pressure due to capillary forces can be offset by the dissolution of CO2 in formation water and its compressibility. Higher capillary forces also reduce gravity segregation, and this gives a more homogeneous CO2 plume which improves the dissolution of CO2. The solubility of CO2 in formation water decreases with increasing salinity which requires an increased injection pressure. Higher salinity and capillary pressure can even block the pores, causing an increased salt precipitation. Simulations with various pressure-temperature conditions and modified salinity and capillary pressure curves dem- onstrate that, with the injection pressures similar for both cold and warm basins at a given injection rate, CO2 dissolves about 10% more in the warm basin water than in the cold basin. The increase in dissolution lowers the injection pressure compensating the disadvantage of low CO2 density and compressibility for storage in warm basins.

Impact of Capillary Pressure, Salinity and In situ Conditions on CO2 Injection into Saline Aquifers

This paper (SPE 110628) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November 2007, and revised for publication. Original manuscript received for review 10 August 2007. Revised manuscript received for review 3 July 2008. Paper peer approved 26 July 2008. Summary We present laboratory experiments to investigate the influence of gravitational, viscous, and capillary effects on the CO2 injection process. Quasi 2D experiments are performed in a vertical glassbead pack in the parameter range of interest for CO2 sequestration in deep aquifers (i.e., with Bond numbers of approximately 10 and capillary numbers on the order of 10). The objective is to investigate the type of flow regimes that occur under favorable as well as unfavorable conditions of density and viscosity. The experiments demonstrate the existence of pore-scale instability in the presence of unfavorable gradients of viscosity and density. Consequently, conventional mathematical models may not be able to represent these unstable flows appropriately. A comparison with estimates from percolation theory shows reasonably good agreement with experimental observations.

Yildiray Cinar

Papers

Injecting pure N2 and CO2 to coal for enhanced coalbed methane: Experimental observations and numerical simulation

Impact of Capillary Pressure, Salinity and In situ Conditions on CO2 Injection into Saline Aquifers

Experimental Study of CO2 Injection Into Saline Formations

An experimental study of improved oil recovery through fines-assisted waterflooding

Carbon dioxide sequestration in saline formations: Part I—Review of the modeling of solubility trapping