Sharpening a Cyclic Solvent Injection Technique in a Heavy Oil Reservoir from the Variation of the Nitrogen Injected as Dispersing: A Field Pilot, Colombia

This paper analyzes the use of a cyclic solvent injection technique (CSI) as a non-thermal EOR alternative to cyclic steam stimulation (CSS) for increasing the heavy oil recovery in a shallow reservoir located at the middle Magdalena basin in Colombia. A pilot well with less than 30% of water-cut and 10.9 °API was selected. Heavy natural gasoline of 30 °API obtained from the same reservoir was injected by using nitrogen (N2) as dispersing gas. Three procedures were performed being the procedure A, a Solvent slug injection of 60 bbl through the annular pushed and dispersed by 46,444 m3 (1,640 Mscf) of N2 immiscible (considering the low reservoir pressure). The procedure B consisted of injecting the same Solvent volume, but this time pushed by a third part of the N2 injected previously 15,481 m3 (547 Mscf). The procedure C consisted of only inject the same N2 volume than B procedure to analyze the heavy oil response without Solvent. There were collected production data, °API (by hydrometer), gas-flow and gas-gravity values using a liquid level software. Knowing the °API of each component in the laboratory—Solvent and heavy oil—the Solvent concentration from the real °API produced in production stages was calculated. All procedures had 48 hours of soaking, followed by a flowing process to tank to carefully release the excess of N2 before starting the production stage, avoiding gas lock issues. Without considering the Solvent injected, incremental oil production in procedure A was 232 bbl, in procedure B was 120 bbl and for procedure C, incremental oil only reached 11 bbl. With the last result it was determined the N2 injection by itself as a production mechanism without the Solvent effect in the in-situ heavy oil had a negligible effect on incremental oil. The gas-gravity showed the gas composition became heavier along the time, this considering the high-frequency N2 injections swept the methane near the well, requiring more time to produce the N2 traces from the porous media. The excess of N2 as a heavy Solvent dispersing mechanism does not warrant a better dilution effect since as observed in A and B procedures, Solvent concentration in the early production stage never dropped below 35% (17 °API), regardless of the N2 volume injected in the first two days. Finally, although A procedure had more incremental oil production (+93% than B), less N2 injected in B procedure was more efficient (+55% than A) regarding the incremental oil and N2 injected ratio (ONR).

Performance Evaluation of Hybrid Thermal-Solvent Injection in a Post-CHOPS Reservoir With Consideration of Wormhole Network

In this paper, techniques have been developed to evaluate performance of thermal, solvents, and hybrid thermal-solvent processes in a post-CHOPS reservoir with consideration of wormhole network. With the experimentally determined properties of injected gases and reservoir fluids, history matching is accomplished for the reservoir geological model conditioned to the fluid and sand production profiles together with pressure. Meanwhile, the wormhole network is characterized with the newly developed pressure-gradient-based (PGB) sand failure criterion. Once the history matching is completed, the calibrated reservoir geological model is then employed to evaluate performance of thermal, solvents, and hybrid thermal-solvent processes under various conditions. It is found that huff-n-puff processes have a very good performance on enhancing oil recovery when wormhole network is fully generated and propagated. Among all solvent-based methods, pure CO2 huff-n-puff process shows a better performance than flue gas, while the addition of alkane solvents leads to a higher oil recovery compared with CO2 only method. Since the addition of C3H8 and n-C4H10 will significantly decrease the heavy oil viscosity and enhance the swelling factor, all hybrid thermal-solvent injection achieves high oil recovery by taking the advantage of both hot steam and solvents injection.

Optimal Control of Vapor Extraction of Heavy Oil

Vapor extraction (Vapex) process is an emerging technology for viscous oil recovery that has gained much attention in the oil industry. However, the oil production rates in Vapex are too low to make it attractive for field implementation. Although several researchers have investigated several aspects of Vapex, there are few reported attempts to enhance oil production in Vapex. This research aims to enhance the same using solvent injection pressure versus time as a control function. For this purpose, the necessary conditions for maximum heavy oil production are derived based on a detailed mass transfer model of the Vapex experiment carried out in this work. These conditions are then used to develop an optimal control algorithm to determine the optimal solvent injection pressure polices to maximize oil production in Vapex. The optimal policies successfully generate 20–35% increase in experimental oil production with propane and butane as pure solvents, and heavy oil of 14,500 mPa·s viscosity in lab scale reservoirs of 25 and 45 cm heights, and 204 Darcy permeability. The accuracy of optimal control is experimentally validated. The results show that the experimental oil production values from the optimal policies are within ± 5% of those predicted by the optimal control algorithm.

Optimal Control of Vapor Extraction of Heavy Oil

Vapor extraction (Vapex) process is an emerging technology for viscous oil recovery that has gained much attention in the oil industry. However, the oil production rates in Vapex are too low to make it attractive for field implementation. Although several researchers have investigated several aspects of Vapex, there are few reported attempts to enhance oil production in Vapex. This research aims to enhance the same using solvent injection pressure versus time as a control function. For this purpose, the necessary conditions for maximum heavy oil production are derived based on a detailed mass transfer model of the Vapex experiment carried out in this work. These conditions are then used to develop an optimal control algorithm to determine the optimal solvent injection pressure polices to maximize oil production in Vapex. The optimal policies successfully generate 20–35% increase in experimental oil production with propane and butane as pure solvents, and heavy oil of 14,500 mPa·s viscosity in lab scale reservoirs of 25 and 45 cm heights, and 204 Darcy permeability. The accuracy of optimal control is experimentally validated. The results show that the experimental oil production values from the optimal policies are within ± 5% of those predicted by the optimal control algorithm.

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.