Permeability and Relative Permeability Measurements at Reservoir Conditions for CO2-Water Systems in Ultra Low Permeability Confining Caprocks

Abstract

Abstract Carbon dioxide has been successfully used in more than 80 enhanced oil recovery (EOR) operations in North America, and the number of such operations may increase significantly around the world if CO2 becomes available at reasonable costs. On the other hand, geological storage in deep saline aquifers and hydrocarbon reservoirs of large amounts of CO2, captured from large stationary sources is one method that is under consideration for reducing greenhouse gas emissions into the atmosphere on a worldwide basis. In both cases of CO2-EOR and CO2 capture and geological storage (CCGS), the containment of CO2 within the injection unit and leakage avoidance are essential. Effective CO2 containment is achieved by the overlying tight caprock that is initially highly saturated with formation brine, which prevents CO2 migration into uphole intervals and potentially into shallow freshwater aquifers and ultimately to the atmosphere. The confining properties of the caprock are due to its very low permeability and to relative permeability and capillary pressure effects that prevent the penetration of CO2 into, and significant flow through the caprock. Essential to the assessment of CO2-EOR and CCGS operations, including numerical simulation, is knowledge about the caprock permeability to brine and CO2. This paper presents results of detailed measurements at full reservoir conditions for permeability to water, primary drainage and secondary imbibition permeability, relative permeability and trapped saturation of supercritical, dense-phase CO2 and brine for three different, regionally-extensive low permeability formations in the Alberta basin, Canada. These formations include Devonian and Cretaceous shales and a Devonian anhydrite whose measured relative permeabilities were found to be in the nano to pico Darcy range. The methodology used in the test program and the results can be extended to the evaluation of other sealing caprocks for other prospective CO2-EOR or CCGS operations around the world. Introduction Carbon dioxide from natural CO2 reservoirs is used for enhanced oil recovery (CO2-EOR) at more than 70 operations in the Permian Basin in west Texas in the United States 1. Other CO2-EOR operations in the U.S. and around the world use CO2 from anthropogenic sources such as gas plants and petrochemical and fertilizer plants. However, the number of these CO2-EOR operations is much smaller due to the high cost of CO2 capture from industrial sources. On the other hand, CO2 capture and geological storage (CCGS) is considered to be a major component of climate change mitigation strategies 2, and, although deep saline aquifers have the largest storage capacity and widest distribution, oil reservoirs are the most likely to be used preferentially for CCGS because of the positive economic potential for increased oil production through CO2-EOR schemes 3,4. Thus, the use of CO2 in CO2-EOR operations and the storage of CO2 in deep saline aquifers are foreseen to increase in the next decades. In both cases it is essential that the caprock, which is saturated with formation water, does not allow the leakage of CO2 from the injection reservoir or aquifer into overlying strata and possibly into shallow groundwater resources or even to the surface. If the caprock is not naturally fractured, then the necessary condition to avoid CO2 leakage is to maintain the injection pressure below the capillary entry pressure or the rock fracturing pressure, whichever is lower. Even if the CO2 pressure is higher than the capillary entry pressure (but lower than the rock fracturing pressure), if the absolute and relative permeabilities of the caprock are exceedingly low, then CO2 may flow through the caprock on a geological time scale, in which case, from operational and CO2-storage points of view it may not be significant. Thus, it is very important to know the CO2-brine displacement characteristics of low permeability rocks, such as shale and anhydrite, which constitute the confining caprock of hydrocarbon reservoirs and deep saline aquifers. Yet very few data are available about the displacement behavior of CO2-brine systems in such low permeability media, as most of the research effort to date has focused on CO2-oil systems in higher quality reservoir rocks. To cover this gap in data and knowledge, the authors commenced in 2004 an experimental program on core plugs taken from rocks at several locations in the Alberta basin, Canada. The rock samples were collected from oil reservoirs where oil producers started CO2-EOR pilot operations using CO2 or acid gas produced at nearby gas plants, and from deep saline aquifers that may be used in the future for CO2 storage.