Effects of Rate, Temperature, and Solvent Type on Vapor/Oil Gravity Drainage (VOGD) in Fractured Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 973-987 ◽  
Author(s):  
Neha Anand ◽  
Brandon Tang ◽  
Bradley (Duong) Nguyen ◽  
Chao-yu Sie ◽  
Marco Verlaan ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Molecular Diffusion ◽  
Operating Temperature ◽  
Fractured Reservoirs ◽  
Viscosity Reduction ◽  
Gravity Drainage ◽  
Asphaltene Precipitation ◽  
Solvent Vapor ◽  
Solvent Type ◽  
High Fluid

Summary Application of thermal and solvent enhanced-oil-recovery (EOR) technologies for viscous heavy-oil recovery in naturally fractured reservoirs is generally challenging because of low permeability, unfavorable wettability and mobility, and considerable heat losses. Vapor/oil gravity drainage (VOGD) is a modified solvent-only injection technology, targeted at improving viscous oil recovery in fractured reservoirs. It uses high fluid conductivity in vertical fractures to rapidly establish a large solvent/oil contact area and eliminates the need for massive energy and water inputs, compared with thermal processes, by operating at significantly lower temperatures with no water requirement. An investigation of the effects of solvent-injection rate, temperature, and solvent type [n-butane and dichloromethane (DCM)] on the recovery profile was performed on a single-fracture core model. This work combines the knowledge obtained from experimental investigation and analytical modeling using the Butler correlation (Das and Butler 1999) with validated fluid-property models to understand the relative importance of various recovery mechanisms behind VOGD—namely, molecular diffusion, asphaltene precipitation and deposition, capillarity, and viscosity reduction. Experimental and analytical model studies indicated that molecular diffusion, convective dispersion, viscosity reduction by means of solvent dissolution, and gravity drainage are dominant phenomena in the recovery process. Material-balance analysis indicated limited asphaltene precipitation. High fluid transmissibility in the fracture along with gravity drainage led to early solvent breakthroughs and oil recoveries as high as 75% of original oil in place (OOIP). Injecting butane at a higher rate and operating temperature enhanced the solvent-vapor rate inside the core, leading to the highest ultimate recovery. Increasing the operating temperature alone did not improve ultimate recovery because of decreased solvent solubility in the oil. Although with DCM, lower asphaltene precipitation should maximize the oil-recovery rate, its higher solvent (vapor)/oil interfacial tension (IFT) resulted in lower ultimate recovery than butane. Ideal density and nonideal double-log viscosity-mixing rules along with molecular diffusivity as a power function of oil viscosity were used to obtain an accurate physical description of the fluids for modeling solvent/oil behavior. With critical phenomena such as capillarity and asphaltene precipitation missing, the Butler analytical model underpredicts recovery rates by as much as 70%.

Effect of Pressure on Vapor/Oil Gravity Drainage in Fractured Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 197-211 ◽  
Author(s):  
Brandon Tang ◽  
Neha Anand ◽  
Bradley Nguyen ◽  
Chao-yu Sie ◽  
Marco Verlaan ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Fractured Reservoirs ◽  
Saturation Pressure ◽  
Injection Rate ◽  
Gravity Drainage ◽  
Operating Pressure ◽  
Asphaltene Precipitation ◽  
Solvent Vapor ◽  
Recovery Processes ◽  
Original Oil In Place

Summary This fundamental research is part of a larger study in determining the capability of a solvent process, referred to as vapor/oil gravity drainage (VOGD), for enhancing gravity drainage of viscous oil in fractured reservoirs by the injection of solvent. The solvent can be designed to traverse the reservoir mostly in its vapor phase at the reservoir temperature and pressure. Heated solvent vapor can also be used to facilitate the propagation of solvent vapor in low-temperature reservoirs, taking advantage of both thermal- and solvent-recovery processes. The experimental setup and corresponding acquired data were previously introduced by the authors in Anand et al. (2018), in which the effects of temperature, solvent-injection rate, and solvent type [n-butane and dichloromethane (DCM)] were investigated. Results from Anand et al. (2018) indicated encouraging high oil rates and ultimate recoveries; results also demonstrated that the oil rates and recovery were affected by diffusion and dispersion (in the form of intrinsic gas rate), asphaltene precipitation, and capillary pressure. The intent of our present work is to further study the mechanisms behind VOGD—in particular, those related to operating pressure and solvent-vapor/oil capillary pressure. The results from this work show that the ultimate recovery and oil rate are positively correlated to the operating pressure; experiments conducted at 50 and 75% saturation pressure (Psat) yielded lower ultimate oil recoveries, ranging from 33 to 68% of original oil in place (OOIP), compared with the experiments conducted at 90% Psat (recovery of 70% OOIP). Moreover, n-butane performed better than DCM, and lower asphaltene precipitation was seen at lower Psat. The main drivers for these observations were found to be lower solvent solubility and larger capillary pressure values at lower values of Psat.

Solvent Selection Criteria and Optimal Application Conditions for Heavy-Oil/Bitumen Recovery at Elevated Temperatures: A Review and Comparative Analysis

2015 ◽  
Vol 138 (1) ◽  
Author(s):  
Khosrow Naderi ◽  
Tayfun Babadagli
Keyword(s):  
Comparative Analysis ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Selection Criteria ◽  
Elevated Temperatures ◽  
Fractured Reservoirs ◽  
Solvent Type ◽  
Wide Range ◽  
Cost Efficient ◽  
Fractured Carbonates

Sole thermal or solvent methods for heavy-oil recovery are not effective enough to deliver cost efficient processes. Hybrid applications of those two techniques have been proposed to take advantage of each and a wide range of investigations have been recently performed focusing on extreme conditions such as bitumen containing sands and carbonates, deep reservoirs, and oil-wet fractured carbonates. What is critically important in these applications is to determine the best performing solvent for a particular application and optimal application conditions for a given solvent at high temperature conditions. In this study, the results from various reported works on the hybrid applications of thermal (mainly steam) and solvent methods were complied, analyzed, and compared. Attention was given to a comparative analysis of steam-over-solvent injection in fractured reservoirs (SOS-FR) method. Steam/solvent methods show a promising outcome in general, while specific modifications must be taken into account for different application situations. These were discussed and specified, especially from proper solvent type and optimal application conditions for alternate injection of steam and solvent in different reservoir types.

Role of molecular diffusion in the recovery of water flood residual oil

2019 ◽  
Author(s):  
Chem Int
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Gravity Drainage ◽  
Co2 Injection ◽  
Initial Water ◽  
Water Imbibition ◽  
Naturally Fractured ◽  
Carbon Dioxide Co2

Traditionally, carbon dioxide (CO2) injection has been considered an inefficient method for enhancing oil recovery from naturally fractured reservoirs. Obviously, it would be useful to experimentally investigate the efficiency of waterflooding naturally fractured reservoirs followed by carbon dioxide (CO2) injection. This issue was investigated by performing water imbibition followed by CO2 gravity drainage experiments on artificially fractured cores at reservoir conditions. The experiments were designed to illustrate the actual process of waterflooding and CO2 gravity drainage in a naturally fractured reservoir in the Brass Area, Bayelsa. The results demonstrate that CO2 gravity drainage could significantly increase oil recovery after a waterflood. During the experiments, the effects of different parameters such as permeability, initial water saturation and injection scheme was also examined. It was found that the efficiency of the CO2 gravity drainage decrease as the rock permeability decreases and the initial water saturation increases. Cyclic CO2 injection helped to improve oil recovery during the CO2 gravity drainage process which alters the water imbibition. Oil samples produced in the experiment were analyzed using gas chromatography to determine the mechanism of CO2-improved oil production from tight matrix blocks. The results show that lighter components are extracted and produced early in the test. The results of these experiments validate the premises that CO2 could be used to recover oil from a tight and unconfined matrix efficiently.

scholarly journals Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3699 ◽  
Author(s):  
Faisal Awad Aljuboori ◽  
Jang Hyun Lee ◽  
Khaled A. Elraies ◽  
Karl D. Stephen
Keyword(s):  
Gravity Model ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Carbonate Reservoir ◽  
Real Field ◽  
Gravity Drainage ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
Matrix Blocks ◽  
The Matrix

Gravity drainage is one of the essential recovery mechanisms in naturally fractured reservoirs. Several mathematical formulas have been proposed to simulate the drainage process using the dual-porosity model. Nevertheless, they were varied in their abilities to capture the real saturation profiles and recovery speed in the reservoir. Therefore, understanding each mathematical model can help in deciding the best gravity model that suits each reservoir case. Real field data from a naturally fractured carbonate reservoir from the Middle East have used to examine the performance of various gravity equations. The reservoir represents a gas–oil system and has four decades of production history, which provided the required mean to evaluate the performance of each gravity model. The simulation outcomes demonstrated remarkable differences in the oil and gas saturation profile and in the oil recovery speed from the matrix blocks, which attributed to a different definition of the flow potential in the vertical direction. Moreover, a sensitivity study showed that some matrix parameters such as block height and vertical permeability exhibited a different behavior and effectiveness in each gravity model, which highlighted the associated uncertainty to the possible range that often used in the simulation. These parameters should be modelled accurately to avoid overestimation of the oil recovery from the matrix blocks, recovery speed, and to capture the advanced gas front in the oil zone.

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