Numerical Simulation of Nonequilibrium Foamy Oil for Cyclic Solvent Injection in Reservoirs after Cold Heavy Oil Production with Sand

Summary Nonequilibrium foamy oil behavior and solvent transport are two important recovery mechanisms for cyclic solvent injection (CSI) processes in post-cold heavy oil production with sand (CHOPS) reservoirs. The nonequilibrium solvent exsolution and gas bubbles generated during the pressure depletion stage have the typical characteristics of foamy oil flow. In this paper, a field-scalepost-CHOPS model is constructed and upscaled from a core model, which was calibrated against detailed experimental data involving various propane (C3H8)-based and carbon dioxide (CO2)-based solvent mixtures. The field model is upscaled from the core model to analyze the impacts of simulation scales, heterogeneous wormholes, and the operating schedules on foamy oil behavior of different solvent systems. Reaction kinetics are implemented to represent the nonequilibrium gas dissolution and exsolution for foamy oil flow. A fractal wormhole network is modeled. To analyze the impacts of pressure depletion strategies, single-stage pressure depletion involving three oil solvent systems, as well as two cycles of CSI production processes, are examined. Detailed sensitivity analyses involving different solvent compositions are discussed. The results illustrate that both C3H8-based and CO2-based solvents exhibit significant nonequilibrium foamy oil characteristics, enabling the oil viscosity to remain close to its value with dissolved solvent during the pressure depletion process. However, the amount of nonequilibrium foamy oil flow is strongly dependent on the pressure depletion rate: A faster depletion rate is beneficial for higher oil recovery. The core model results are more sensitive to the solvent types, whereas the field-scale simulations show comparable recovery performance for both C3H8-based and CO2-based solvents. This observation highlights the significance of domain size, time scale, and wormhole heterogeneities on the ensuing foamy oil behavior. Although several post-CHOPS models were developed in the past, detailed field-scale models that simulate nonequilibrium foamy oil kinetics in a realistic wormhole network are lacking. The simulation model developed here has been calibrated against detailed experimental measurements and upscaled from a core-scale model. Improving our understanding of solvent dissolution/exsolution would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.

Characterization of Foamy Oil and Gas/Oil Two-Phase Flow in Porous Media for a Heavy Oil/Methane System

In our previous study, a series of experiments had been conducted by applying different pressure depletion rates in a 1 m long sand-pack. In this study, numerical simulation models are built to simulate the lab tests, for both gas/oil production data and pressure distribution along the sand-pack in heavy oil/methane system. Two different simulation models are used: (1) equilibrium black oil model with two sets of gas/oil relative permeability curves; (2) a four-component nonequilibrium kinetic model. Good matching results on production data are obtained by applying black oil model. However, this black oil model cannot be used to match pressure distribution along the sand-pack. This result suggests the description of foamy oil behavior by applying equilibrium black oil model is incomplete. For better characterization, a four-component nonequilibrium kinetic model is developed aiming to match production data and pressure distribution simultaneously. Two reactions are applied in the simulation to capture gas bubbles status. Good matching results for production data and pressure distribution are simultaneously obtained by considering low gas relative permeability and kinetic reactions. Simulation studies indicate that higher pressure drop rate would cause stronger foamy oil flow, but the exceed pressure drop rate could shorten lifetime of foamy oil flow. This work is the first study to match production data and pressure distribution and provides a methodology to characterize foamy oil flow behavior in porous media for a heavy oil/methane system.

Relative Permeability of Foamy Oil for Different Types of Dissolved Gases

Summary Foamy-oil flow is encountered not only during the primary stage of the cold-heavy-oil-production (CHOP) process through evolving methane originally in the oil but also in the post-CHOP enhanced-oil-recovery (EOR) applications in which different gases are injected and dissolved in heavy oil. Despite remarkable efforts on the physics of foamy oil flow, the mechanics of its flow through porous media is not properly understood yet. This is mainly because of lack of detailed experimental studies at the core scale to clarify the physics of the process and to support numerical-modeling studies. One also should test foamy-oil flow for different types of EOR gases dissolved and evolved at different conditions under pressure depletion. The objective of the present work is to perform detailed laboratory experiments on foamy-oil flow through porous media. Pressure/volume/temperature (PVT) studies were conducted to determine the actual pressure ranges in the coreflooding experiments in the beginning. After dissolving different gases in dead oil at 400 psi for methane (CH4) and carbon dioxide (CO2) and 112 psi for propane, the oil was injected into a sandpack to saturate it. The solution-gas-drive test was started by opening the outlet valve of the coreholder after reaching equilibrium. To mimic typical post-CHOP EOR conditions with methane, propane, or CO2 injection, the pressure was kept high (400 psi for CO2 and CH4 and 112 psi for propane). The produced oil by solution-gas drive and the gas evolved were monitored by collecting them in a graduated cylinder and a gas cylinder, respectively, while the pressure was recorded by an automatic data-acquisition system. The experimental data provided information about the effect of initial pressure of the depletion test in the amount of oil and gas measured as well as the visual observations of bubble characteristics of the foamy oil. Results showed that, among the three gases, CO2 is a good candidate for foamy oil. Maximum oil recovery [more than 50% of original oil in place (OIP) (OOIP)] was obtained in case of CO2.