Investigating Impact of Flow Rate and Wettability on Residual Trapping in CO2 Storage in Saline Aquifers through Relative Permeability Experiments

Mansour Soroush,Dag Wessel-Berg,Jon Kleppe,Ole Torsaeter

doi:10.5539/eer.v3n2p53

Abstract

In order to investigate effects of injection rate and aquifer influx in imbibition processes and also wettability behaviour for CO2 storage in aquifers, two representative fluids are chosen for relative permeability measurements. These two fluids represent CO2 and brine at the reservoir conditions. The first set of experiments is done by n-heptane and a mixture of glycerol and water, flowing in a glass beads porous medium. The density difference and viscosity ratio are designed to be in the range of CO2-brine systems normally found at reservoir conditions. Another set of experiments is designed based on dodecane and a mixture of glycerol and water. The second mixture is chosen so that the same ratios of density differences and viscosity ratios are maintained. Interfacial tension and contact angles are measured for both cases. By this set up, two cases of strongly water-wet and water-wet systems are designed. The purpose of this study is to quantify the impact of wettability and flow rate through relative permeability experiments. Results show that the relative permeability is sensitive to both rate and wettability, and after interpreting the data from experiments in a history matching process, based on the effects of drainage and imbibition rates and also the effect of wettability, correlations are developed to predict the amount of CO2 trapped in the pores. This newly developed method will be useful in obtaining good estimations of real case trapping volume in CO2 storage processes. Scaling analysis of the experiment shows that the tests are well designed in the range of real reservoir conditions.

Highlights

A good option for reduction of the emission of CO2 to the atmosphere is CO2 capture and storage (Bennion & Bachu, 2005)
According to the measured absolute permeability and by using history matching of pressure drop and production, the best relative permeability model is matched to the data
Imbibition tests are completed after the drainage test with the highest rate

Summary

Introduction

A good option for reduction of the emission of CO2 to the atmosphere is CO2 capture and storage (Bennion & Bachu, 2005). CO2 storage in geological formations is considered to be an important solution for preventing CO2 emissions to the atmosphere; it is vital to ensure safe and secure storage projects. There are many potential geological storage possibilities including depleted oil and gas reservoirs and coal beds, but the main attraction of brine formations as suitable storage sites for CO2 is the availability and possibly larger volumes (Bennion & Bachu, 2005). One of the important issues in the modeling process is the relative permeability (the ability of flow of a fluid through a porous material in presence of other fluid) of the CO2-brine system Relative permeabilities of these systems are influenced by different reservoir parameters such as absolute permeability (the ability of flow of a fluid through a porous material), temperature, wettability, hysteresis effect, interfacial tension and displacement rates. Many factors have been targeted for the studies in previous petroleum researches, but not many specific research projects on CO2-brine systems are reported (Perrin et al, 2009; Pini et al, 2011; Krever et al, 2011)

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Results