The Impact of Interfacial Tension and Pore-Size Distribution/Capillary Pressure Character on CO2 Relative Permeability at Reservoir Conditions in CO2-Brine Systems

Abstract

Injection of CO2 has been used for enhanced oil recovery (EOR) in many light and medium gravity reservoirs. Consequently, sequestration of CO2 in oil reservoirs in conjunction with CO2-EOR is a method that is under consideration for reducing CO2 emissions into the atmosphere. Many oil reservoirs are underlain by an aquifer, and EOR processes often involve water-alternating-gas (WAG) processes. Proper understanding of the relative permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 injection and sequestration sites. While many measurements exist for CO2-oil systems, very few data, if any, exist for CO2-brine systems. This paper provides an analysis of brine-CO2 interfacial tension (IFT) measurements that were conducted for equilibrium brines and CO2 at reservoir conditions, and the detailed 700 MPa mercury-injection capillary pressure tests conducted on all rock samples to determine specific pore size distributions. Three sandstone and three carbonate potential sequestration zones in the Wabamun Lake area in Alberta, Canada, were evaluated, together with a caprock shale. This data set has specific application to the study of the behavior of injected CO2 in contact with bottom water or water-saturated zones that may be encountered in CO2-EOR projects, as well as for CO2 sequestration in deep saline aquifers. The analysis shows some correlation between the CO2-brine IFT, pore size distribution of the intergranular porous media and CO2-brine relative permeability. However, due to the high degree of variability in the pore system character of the different sandstone and carbonate facies tested, additional, better-controlled comparative tests are required to validate these trends. The hope is that, ultimately, compilation of more extensive datasets will allow appropriate selection of proper CO2-brine relative permeability relationships at reservoir conditions for intergranular sandstone and carbonate formations on the basis of relatively simple measurements of pore system geometry and IFT. These data will also provide a valuable tool for the estimation of CO2-brine relative permeability for the simulation and evaluation of intergranular sandstone and carbonate formations on a worldwide basis.

Use of low- and high-IFT fluid systems in experimental and numerical modelling of systems that mimic CO2 storage in deep saline formations

“…Calculations for both, the storage sites and sedimentary basins, are made for the range of the flow rates used in the experiments. IFT is calculated according to the equation IFT=59.335/P 0.2446 (P -formation pressure, MPa) from [11]. The large difference between basins and existing storage sites that can be seen in Figure 4a is caused mainly by two parameters: permeability and formation thickness.…”

A study of relative permeability parameters on rock cores using a two-phase flow test

“…Toth et al (2001) emphasized that the capillary end-effects will normally affect the measurement accuracy both in a displacement method and a steady state method; however, the effect can be minimized if the injection rate can be increased to some extent in a displacement method. By mercury-injection capillary pressure tests conducted on rock samples, Bennion and Bachu (2006) depicted the impact of interfacial tension and poresize distribution/capillary pressure characteristics on relative permeability with regard to CO 2 within reservoir conditions in a CO 2 -brine system. Unfortunately, how capillary behavior inside the rock voids affects core flooding under a twophase laboratory environment remains uncertain and is only qualitatively known.…”

Phase II Final Scientific/Technical Report

“…Capillary pressure functions between supercritical CO 2 and liquid were adapted from Parker et al (1987) and calibrated from data of Bennion and Bachu (2006). Capillary pressure between oil and brine were measured from SACROC cores (Core128V, 136V, and 191V) at 50°C and 1.4…”