Kristian Jessen

Storage of CO2 in saline aquifers: Effects of gravity, viscous, and capillary forces on amount and timing of trapping

CO2 can be effectively immobilized during CO2 injection into saline aquifers by residual trapping – also known as capillary trapping – a process resulting from capillary snap-off of isolated CO2 bubbles. Simulations of CO2 injection were performed to investigate the interplay of viscous and gravity forces and capillary trapping of CO2. Results of those simulations show that gas injection processes in which gravitational forces are weak compared to viscous forces (low gravity number Ngv) trap significantly more CO2 than do flows with strong gravitational forces relative to the viscous forces (high Ngv). The results also indicate that over a wide range of gravity numbers (Ngv), significant fractions of the trapping of CO2 can occur relatively quickly. The amount of CO2 that is trapped after injection ceases is demonstrated to correlate with Ngv. For some simulated displacements, effects of capillary pressure and aquifer dip angle on the amount and the rate of trapping are reported. Trapping increases when effects of capillary pressure and aquifer inclination are included in the model. Finally we show that injection schemes such as alternating injection of brine and CO2 or brine injection after CO2 injection can also enhance the trapping behavior.

Analytical Theory of Coalbed Methane Recovery by Gas Injection

Injection of either carbon dioxide (CO2) or nitrogen (N2) enhances recovery of coalbed methane. In this paper, we provide new analytical solutions for the flow of ternary gas mixtures in coalbeds. The adsorption/desorption of gaseous components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas-phase behavior is predicted by the PengRobinson equation of state (EOS). Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan basin (U.S.A.). In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution consisting of continuous waves and shocks is found. Mixtures of CH4, CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems where the initial gas is largely CH4, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time, and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time coalbed methane (CBM) is recovered.

Recovery of Coalbed Methane by Gas Injection

Injection of either carbon dioxide (CO2) or nitrogen (N2) can serve as an effective method for enhanced recovery of coalbed methane. In this paper, we provide new analytical solutions for flow of ternary gas mixtures. The adsorption/desorption of the components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas phase behavior is predicted by the Peng-Robinson EOS. Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan Basin of Colorado. In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution that consists of continuous waves and shocks is found. Mixtures of CH4, CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems in which the initial gas has a high CH4 content, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time CBM is recovered.

An Experimental and Numerical Investigation of Crossflow Effects in Two-Phase Displacements

In this paper, we present flow visualization experiments and numerical simulations that demonstrate the combined effects of viscous and capillary forces and gravity segregation on crossflow that occurs in two-phase displacements in layered porous media. We report results of a series of immiscible flooding experiments in 2D, two-layered glass bead models. Favorable mobilityratio imbibition and unfavorable mobility-ratio drainage experiments were performed. We used pre-equilibrated immiscible phases from a ternary isooctane/isopropanol/water system, which allowed control of the interfacial tension (IFT) by varying the isopropanol concentration. Experiments were performed for a wide range of capillary and gravity numbers. The experimental results illustrate the transitions from flow dominated by capillary pressure at high IFT to flow dominated by gravity and viscous forces at low IFT. The experiments also illustrate the complex interplay of capillary, gravity, and viscous forces that controls crossflow. The experimental results confirm that the transition ranges of scaling groups suggested by Zhou et al. (1994) are appropriate/valid. We report also results of simulations of the displacement experiments by two different numerical techniques: finite-difference and streamline methods. The numerical simulation results agree well with experimental observations when gravity and viscous forces were most important. For capillary-dominated flows, the simulation results are in reasonable agreement with experimental observations.

Code Intercomparison Builds Confidence in Numerical Models for Geologic Disposal of CO2

Publisher Summary Different kinds of subsurface reservoirs have been proposed for geologic disposal of greenhouse gases, including saline aquifers (brine formations), depleted or depleting oil and gas reservoirs, and coalbeds. Injection of greenhouse gases into such formations will give rise to complex coupled processes of fluid flow, mechanical and chemical changes, and heat transfer. Mathematical models and numerical simulation tools will play an important role in evaluating the feasibility of geologic disposal of CO 2 , and in designing and monitoring CO 2 disposal operations. The models must accurately represent the major physical and chemical processes induced by injection of CO 2 into potential disposal reservoirs, such as miscible and immiscible displacement, partitioning of CO 2 among different fluid phases, chemical reactions, thermal effects, and geomechanical changes from increased pore pressures. It is essential to test and evaluate numerical simulation codes to establish their ability to model these processes in a realistic and quantitative fashion. The code inter-comparison study reported in this chapter is a first step in this direction.

Theoretical Analysis of Capillary Rise in Porous Media

In this work, we study the dynamics of capillary-driven fluid invasion in three different settings including: (1) a single capillary tube, (2) a homogeneous porous medium, and (3) a fractured porous medium. A Lambert W functional form is proposed to describe the invasion dynamics in a single capillary tube, that predicts both early-time Washburn-type behavior (

Dual-Porosity Coarse-Scale Modeling and Simulation of Highly Heterogeneous Geomodels

\sqrt{t}

Image-based modeling of gas adsorption and deformation in porous media

t) and late-time behavior. We extend the formulation to describe homogenous porous media and to include viscosity, pressure, and gravity effects in both advancing and defending fluids. Solutions for closed systems, where the advancing fluid compresses the defending fluid, are then developed. Finally, we extend the theory to describe fractured systems and propose a convolution integral formulation and a new explicit solution for fluid invasion into a fractured porous medium.