Combined Cyclic Solvent Injection and Waterflooding in the Post-Cold Heavy Oil Production with Sand Reservoirs

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.

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An Experimental Study of the Post-CHOPS Cyclic Solvent Injection Process

Journal of Energy Resources Technology ◽

10.1115/1.4029972 ◽

2015 ◽

Vol 137 (4) ◽

Cited By ~ 20

Author(s):

Zhongwei Du ◽

Fanhua Zeng ◽

Christine Chan

Keyword(s):

Production Rate ◽

Oil Recovery ◽

Heavy Oil ◽

Early Time ◽

Oil Production ◽

The Other ◽

Late Time ◽

Solvent Injection ◽

Injection Process ◽

Different Diameters

Cold heavy oil production with sand (CHOPS) has been applied successfully in many oil fields in Canada. However, typically only 5–15% of the original oil in place (OOIP) is recovered during cold production. Therefore, effective follow-up techniques are of great importance. Cyclic solvent injection (CSI), as a post-CHOPS process, has greater potential than continuous solvent injection to enhance heavy oil recovery. Continuous solvent injection results in early breakthrough due to the existence of wormholes; while in CSI process, the existence of wormholes can increase the contact area of solvent and heavy oil and the wormholes also provide channels that allow diluted oil to flow back to the wellbore. In this study, the effects of wormhole and sandpack model properties on the performance of the CSI process are experimentally investigated using three different cylindrical sandpack models. The length and diameter of the base model are 30.48 cm and 3.81 cm, respectively. The other two models, one with a larger length (i.e., 60.96 cm) and the other with a larger diameter (i.e., 15.24 cm), are used for up-scaling study in the directions parallel and perpendicular to the wormhole, respectively. The porosity and permeability of these models are about 35% and 5.5 Darcy typically. A typical western Canadian oil sample with a viscosity of 4330 mPa·s at 15 °C is used. And pure propane is selected as the solvent. The experimental results suggest that the existence of wormhole can significantly increase the oil production rate. The larger the wormhole coverage is, the better the CSI performance obtained. In terms of the effect of wormhole's location, a reservoir or well with wormholes developed at bottom is more favorable for post-CHOPS CSI process due to the gravity effect. The production of the CSI process can be divided into two phases: early time chamber rising and late time chamber spreading phases. The oil recovery factor in the chamber rising phase is almost independent of the sandpack model diameter; and the oil relative production rates (the oil production rate divided by the OOIP) in two models with different diameters are close during the chamber spreading phase due to similar solvent dispersion rate. It is also found that if the wormhole length is the same, the sandpack model length hardly affects the oil production rate in the earlier stage. In terms of the effects of the wormhole orientation, the well with a horizontal wormhole is inclined to get a good CSI performance. Through analyzing the experimental data, a relationship of oil production rate to drainage height is also obtained and verified.

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

10.2118/205228-ms ◽

2021 ◽

Author(s):

Andres Solano Arias ◽

Edgar Garzon Navarro ◽

Fernando Contreras Munevar ◽

Isaac Luque Ortiz

Keyword(s):

Oil Recovery ◽

Heavy Oil ◽

Gas Flow ◽

Oil Production ◽

Dilution Effect ◽

Injection Technique ◽

Solvent Concentration ◽

Solvent Injection ◽

Production Stage ◽

Production Stages

Abstract 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).

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Enhanced Oil Recovery in Post-CHOPS Cold Heavy Oil Production with Sand Heavy Oil Reservoirs of Alberta and Saskatchewan Part 2 : Field Piloting of Cycling Solvent Injection

10.2118/199947-ms ◽

2020 ◽

Author(s):

Gokhan Coskuner ◽

Haibo Huang

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Heavy Oil ◽

Oil Production ◽

Oil Reservoirs ◽

Solvent Injection ◽

Heavy Oil Reservoirs

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Optimal Control of Vapor Extraction of Heavy Oil

10.32920/ryerson.14656212 ◽

2021 ◽

Author(s):

Hameed Muhamad

Keyword(s):

Optimal Control ◽

Heavy Oil ◽

Control Algorithm ◽

Injection Pressure ◽

Oil Production ◽

Transfer Model ◽

Vapor Extraction ◽

Solvent Injection ◽

Production Values ◽

Optimal Policies

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.

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