Amir Kianinejad

The effect of saturation path on three-phase relative permeability

Simulation and fluid flow prediction of many petroleum enhanced oil recovery methods as well as environmental processes such as carbon dioxide (CO2) geological storage or underground water resources remediation requires accurate modeling and determination of relative permeability under different saturation histories. Based on this critical need, several three-phase relative permeability models were developed to predict relative permeability; however, for practical purposes most of them require a variety of parameters introducing undesired complexity to the models. In this work, we attempt to find out if there is a simpler way to express this functionality. To do so, we experimentally measure three-phase, water/oil/gas, relative permeability in a 1-m long water-wet sand pack, under several saturation flow paths to cover the entire three-phase saturation space. We obtain the in-situ saturations along the sand pack using a CT scanner and then determine the relative permeabilities of liquid phases directly from the measured in-situ saturations using an unsteady-state method. The measured data shows that at a specific saturation, the oil relative permeability varies significantly (up to 2 orders of magnitude), depending on the path through saturation space. The three-phase relative permeability data are modeled using standard relative permeability models, Corey-type and Saturation Weighted Interpolation (SWI). Our measured data suggest that three-phase oil relative permeability in water-wet media is only a function of its own saturation if the residual oil saturation is treated as a function of two saturations. We determine that residual saturation is the key parameter in modeling three-phase relative permeability (effect of saturation history). This article is protected by copyright. All rights reserved.

An extended JBN method of determining unsteady state two-phase relative permeability

Relative permeability is the reduction of permeability of porous media when subjected to multi-phase flow and a key parameter in subsurface hydrology. The JBN method [Welge, 1952; Johnson et al., 1959] is a well-known method of obtaining relative permeability, which measures the overall pressure drop and the effluent phase ratio versus time during two-phase displacements. By assuming no capillary pressure or gravity, the JBN method obtains the relative permeabilities to both phases at the core outlet. Since data across a range of saturations are acquired in a relatively short time, this method is widely used. This work extends the JBN method by having (1) section-wise pressure drop measurements between the core inlet, four pressure taps on the core and the outlet, (2) local saturation measurements, and (3) local phase fluxes. With these data, the extended JBN method can determine relative permeabilities to both phases at each pressure tap of the core (not just at the core outlet). The JBN extension is shown using a data set where CO2 invades a brine-filled core. From this it is found that the advantages of the extended JBN method over the regular JBN method are: (1) four times more data are obtained, and (2) data are more accurate because the capillary end effect is experimentally avoided. Avoiding the end effect results in tripling the saturation range, and obtaining relative permeabilities that are consistent with steady-state measurements and roughly 40% higher than those from the regular JBN method. This article is protected by copyright. All rights reserved.

Steady‐state supercritical CO2 and brine relative permeability in Berea sandstone at different temperature and pressure conditions

We measure steady-state two-phase supercritical CO2-brine relative permeabilities in a 61-cm-long Berea sandstone core at three different conditions (40°C and 12.41 MPa, 40°C and 8.27 MPa, and 60°C and 12.41 MPa) under primary drainage. We use pressure taps to obtain pressure drops of individual sections of the core, and X-ray Computed Tomography (CT) to obtain in situ saturation profiles, which together help to mitigate the capillary end effect. We include previously measured relative permeabilities at 20°C and 10.34 MPa, and compare all the data using both an eye-test and a statistical test. We find no appreciable temperature and pressure dependence of CO2 relative permeability within 20-60°C and 8.27-12.41 MPa. We find slight changes in the brine relative permeability between supercritical CO2 conditions (40-60°C and 8.27-12.41 MPa) and the liquid CO2 condition (20°C and 10.34 MPa). The temperature and pressure independence of CO2 relative permeability has been previously recognized and reassured in this work using a capillary-effect-free method. This allows one to use a single CO2 relative permeability curve in modeling two-phase CO2 flow within 20-60°C and 8.27-12.41 MPa.

Supercritical CO2 - Brine Primary Drainages (40-60C, 8-12 MPa)

This project includes porosity images and steady-state water saturation images at 8 different positions (distance from inlet are 4, 12, 20, 28, 37, 44, 52 and 59 cm) along a 60-cm long Berea sandstone core (45 mD) during three primary drainage experiments conducted at 40C & 12 MPa, 40C & 8.3 MPa, and 60C & 12 MPa. The drainage experiment starts with injecting 1:1 volume ratio of CO2 and brine. After steady state is reached, the water fractional flow (fw) is lowered. This is repeated until 100% CO2 injection. Each drainage experiment has three steps with fw of 0.5, 0.1 and 0.