Summary Thermal enhanced oil recovery (TEOR) is the most widely accepted method for exploiting the heavy oil reservoirs in North America. In addition to improving the mobility of oil due to its viscosity reduction, the high temperature down in the hole due to the injection of the vapor phase may significantly alter the fluid flow performance and behavior, as represented by the relative permeability to fluids in the formations. Therefore, in TEOR, the relative permeabilities can change with a change in temperature. Also, there is no model that accounts for the change in temperature on two-phase gas/oil relative permeability. Further, the gas/oil relative permeability and its dependence on temperature are required data for the numerical simulation of TEOR. Very few studies are available on this topic with no emerging consensus on a general behavior of such effects. The scarcity of such studies is mostly due to experimental problems to make reliable measurements. Therefore, the primary objective of this study was to overcome the experimental issues and investigate the effect of temperature on gas/oil relative permeability. Oil displacement tests were carried out in a 45-cm-long sandpack at temperatures ranging from 64°C to 210°C using a viscous mineral oil (PAO-100), deionized water, and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to interpret the relative permeability curves for gas/heavy oil systems using the experimentally obtained displacement results. We noted that at the end of gasflooding, the “final” residual oil saturation (Sor) still eluded us even after several pore volumes (PVs) of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. The complete two-phase gas/heavy oil relative permeability curves are inferred with a newly developed systematic history-matching algorithm in this study. This systematic history-matching technique helped us to determine the uncertain parameters of the oil/gas relative permeability curves, such as the two exponents of the Corey equation (No and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted, except these four parameters (i.e., Corey exponents, true residual oil saturation, and gas endpoint relative permeability) were interpreted from simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.

The reservoir fluid flow is characterized by relative permeability data, whose measurements are conventionally made in the laboratory on the cores acquired downhole of different rock types. The major drawback of such conventional core (SCAL) studies is their inability to capture the native wettability and in-situ reservoir fluid flow characteristics. Moreover, this lab based relative permeability data is sometimes unavailable, which requires one to estimate the relative permeability curves based on understanding of the reservoir or public literature and further tune the curves to match the actual pressure and production history of the reservoir during dynamic modelling. This process also incurs additional cost and requires additional time and efforts. Hence, an attempt has been made in this study to develop a novel workflow to estimate the relative permeability curves downhole using formation testers. This new method for interpreting relative permeability curves will complement the already existing conventional methods like SCAL and can also be used directly in the absences of lab data. In this approach, the Single Probe (PS), Pump Out (PO), and Fluid Analyzer (FA) modules of the Modular Formation Dynamic Tester (MDT) tool were assembled and set at the desired depth. Subsequently, the PO module was used to draw out the fluids from the formation and aid in recording the production and pressure drawdown data. The relative permeability of both oil and water phases were estimated at endpoint saturation using steady state approach, and the JBN method was applied after breakthrough and during transition phase using the displacement data (production and pressure data). The advanced well logs were used to interpret the other reservoir properties like porosity, permeability, and etc.

Oil displacement tests were carried out in a 45-cm long sand-pack at temperatures ranging from 64 to 217 °C using a viscous oil (PAO-100), deionized water and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to assess the effect of temperature on gas/oil relative permeability in viscous oil systems. We employed a new systematic algorithm to successfully implement a history matching scheme to infer the two-phase gas/heavy oil relative permeabilities from the core-flood data. We noted that at the end of the gas flooding, the "final" residual oil saturation still eluded us even after tens of pore volumes of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. A history-matching technique was used to determine the uncertain parameters of the oil/gas relative permeability curves, including the two exponents of the extended Corey equation (N° and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted. The remaining four parameters (i.e., Corey exponents, true residual oil saturation and gas endpoint relative permeability) were obtained from history matched simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.

Thermal Enhanced Oil Recovery (TEOR) such as SAGD, CSS and other steam injection processes have been employed in heavy oil reservoirs of North-American and Middle-East countries for oil recovery. Elevation of temperature during this process leads to wettability alteration, IFT variation, viscosity reduction, asphaltene and resin precipitation. These variations during TEOR impact relative permeability to each fluid phase in the reservoirs. Therefore, available models like the Corey model and Stone's model for estimating the relative permeability cannot be directly used for reservoir simulation/modelling study of such reservoir where TEOR is implemented. Hence, an attempt has been made to develop a reliable, accurate, and robust data-driven model for two-phase oil/water relative permeability using the XG-Boost machine learning algorithm which accounts for the temperature's effect. For this study, numerous sets of oil and relative permeability data have been sourced, compiled and validated using our proposed model via the supervised XG-Boost approach. For model construction, 1270 oil relative permeability and 1230 water relative permeability data points were obtained from literature covering different rock/fluid and reservoir conditions. This study presents a new data-driven model developed using the XG-Boost algorithm to predict two-phase oil/water relative permeability over a wide range of temperatures in unconsolidated sand and sandstone formations. Moreover, the proposed model gave us better results based on the statistical error analysis.