Relative permeability hysteresis and capillary trapping characteristics of supercritical CO2/brine systems: An experimental study at reservoir conditions
Highlights
► A major portion of the initial SCO2 can be trapped by brine imbibition. ► Relative permeability hysteresis was characterized using steady-state method. ► A rapid reduction in imbibition relative permeability of scCO2 was observed. ► For a given Sw, imbibition krw was greater than drainage value.
Introduction
Capturing CO2 from stationary sources and injecting it into underground geologic formations for storage purposes is currently receiving significant attention as a potentially viable option for geologic storage and ultimate sequestration of significant quantities of CO2. Among various geologic formations, deep saline aquifers are considered important CO2 sinks because of their potential storage capacity for large volumes of carbon dioxide. It has been reported that saline aquifers have a global storage capacity of 400–10000 Gt of CO2 [1], [2].
In the sequestration process, CO2 captured from commercial or industrial operations is injected into deep salt water aquifers to prevent its emission to the atmosphere. The depth of the aquifers provides the pressurized environment necessary to keep the CO2 at supercritical conditions, namely at pressure and temperature conditions above the critical point of CO2, (Tc = 30.978 °C, Pc = 7.377 MPa [3]). Conditions that support the existence of supercritical CO2 (scCO2) should be present at depths greater than about 750 m. The average depth of the formations targeted for CO2 storage range from about 1000 m, for shallow sites, to 3000 m for deeper cases. Therefore density of scCO2 and brine may vary from 266 to 733 kg/m3 and 945 to 1230 kg/m3, respectively, depending on pressure and temperature conditions [4].
Carbon dioxide injected into a geologic formation may be sequestrated through four mechanisms [5]: (1) structural and stratigraphic trapping: CO2 may stay as a large continuous plume which moves while more of the fluid is injected. The plume gets trapped below low permeability caprocks. At the pore-level, this is equivalent to well-connected clusters of CO2 that reside at the centers of the pores and throats; (2) residual trapping: CO2 may also stay as a stagnant residual phase. This is the CO2 that gets trapped, for instance, after CO2 injection is terminated. It is a consequence of displacement process named imbibition that may take place due to pressure gradients, background velocity of aquifer or chase brine injection. During this process, CO2 gets trapped, in water-wet systems, by displacement mechanisms such as snap-off and pore-body filling. At the pore-level, the trapped CO2 resides in randomly distributed trapped stagnant clusters. The elements of these clusters are CO2 sitting at the centers of larger pores and throats as the non-wetting phase; (3) solubility trapping: CO2 can also dissolve in brine forming an acidic solution. The amount of dissolution is controlled by pressure, temperature, salinity of brine, dispersion, and Darcy velocity of the aqueous phase; and (4) mineral trapping: acidic solution formed owing to dissolution of CO2 in brine may react with the hosting rocks producing secondary minerals that may precipitate indirectly sequestrating carbon. These reactions are relatively slow and therefore this sequestration mechanism becomes important over larger time scales. Carbon sequestrated through this mechanism, however, has the lowest risk of leakage.
From the above-mentioned geologic storage mechanisms, it is evident that stratigraphic and capillary trapping of CO2 are the principal short-term trapping processes. The dynamics of these two mechanisms are directly controlled by their respective relative permeability functions and associated hysteresis as well as residual trapping trends. Therefore, it is essential to carefully investigate these properties to develop an improved understanding of their characteristics under different flow conditions relevant to those seen in deep saline acquires.
Over the last decade several experimental studies of CO2/brine flow systems in various rock samples have been performed. Researchers have used unsteady-state [6], [7], [8], [9], [10], [11], [12], [13] and steady-state [14], [15], [16], [17] core-flooding techniques to measure initial brine and residual CO2 saturations, drainage and imbibition relative permeabilities, and other system properties under different flow, temperature, and pressure conditions. Table 1, Table 2 provide a list of these experimental studies with their experimental techniques and the properties they report.
In this work, we present the results of an experimental study that, for the first time, carefully characterizes relative permeability hysteresis using steady-state method. We also use unsteady-state technique to investigate sensitivity of residual CO2 trapping to variations in initial brine saturation at different flow conditions and fluid properties (scCO2 and gCO2). We study drainage and imbibition flow experiments in three different outcrop sandstone core samples using a reservoir-conditions core-flooding apparatus. All the experiments were performed through vertically-placed cores while a CT scanner is used to measure in-situ saturations.
This paper is structured as follows. First we present a section on the rock samples and fluids as well as experimental conditions, setup, and procedure used in this study. We then include two large categories of results generated using (A) unsteady-state and (B) steady-state core-flooding techniques. In each category we present findings for displacement of brine due to CO2 injection (to establish ) and trapping of CO2 due to brine flood. We include results for both supercritical and gaseous CO2 and discuss the trends using pore-level physics and displacement mechanisms. A section on dissolution of trapped scCO2 is also included that shows the formation of dissolution front along the length of the sample at various stages of the process.
Section snippets
Experiments
In this section, we present detailed information regarding the material and experimental conditions, setup, and procedure used in this study.
Results
In this section we present results of the two categories of flow experiments mentioned earlier, i.e., (A) Unsteady-state, and (B) Steady-state tests. Table 4 lists the number of experiments that were performed along with their corresponding experimental conditions.
Conclusions
We used a robust full-recirculation core-flooding system to perform thirty drainage and imbibition CO2/brine flow experiments at reservoir conditions in three different sandstone core samples. The flow test were performed at various flow conditions and fluid properties (gCO2 and scCO2). Both unsteady- and steady-state core-flooding techniques were employed. We used a medical CT scanner to measure in-situ saturations during the experiments and developed a specific technique to maintain an
Acknowledgment
We gratefully acknowledge financial support of the Department of Energy, Encana, and The School of Energy Resources and the Enhanced Oil Recovery Institute at the University of Wyoming.
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