scholarly journals Enhanced oil recovery in shale reservoirs by gas injection

2015 ◽  
Vol 22 ◽  
pp. 252-259 ◽  
Author(s):  
James J. Sheng
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Shale Reservoirs

Applicability of Enhanced Oil Recovery techniques on mature fields - Interest of gas injection

2005 ◽  
Author(s):  
Frederic Maubeuge ◽  
Danielle Christine Morel ◽  
Jean-Pierre Charles Fossey ◽  
Said Hunedi ◽  
Jacques Albert Danquigny
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Recovery Techniques

scholarly journals Thermal Stability and Compatibility of Surfactants in Presence of Formation Water Salinity under Reservoir Conditions

2020 ◽  
Vol 39 (4) ◽  
pp. 826-830
Author(s):  
Muhammad Khan Memon ◽  
Ubedullah Ansari ◽  
Habib U Zaman Memon
Keyword(s):  
Thermal Stability ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Water Salinity ◽  
Formation Water ◽  
Reservoir Temperature ◽  
Gas Mobility ◽  
Formation Water Salinity

In the surfactant alternating gas injection, the injected surfactant slug is remained several days under reservoir temperature and salinity conditions. As reservoir temperature is always greater than surface temperature. Therefore, thermal stability of selected surfactants use in the oil industry is almost important for achieving their long-term efficiency. The study deals with the screening of individual and blended surfactants for the applications of enhanced oil recovery that control the gas mobility during the surfactant alternating gas injection. The objective is to check the surfactant compatibility in the presence of formation water under reservoir temperature of 90oC and 120oC. The effects of temperature and salinity on used surfactant solutions were investigated. Anionic surfactant Alpha Olefin Sulfonate (AOSC14-16) and Internal Olefin Sulfonate (IOSC15-18) were selected as primary surfactants. Thermal stability test of AOSC14-16 with different formation water salinity was tested at 90oC and 120oC. Experimental result shows that, no precipitation was observed by surfactant AOSC14-16 when tested with different salinity at 90oC and 120oC. Addition of amphoteric surfactant Lauramidopropylamide Oxide (LMDO) with AOSC14-16 improves the stability in the high percentage of salinity at same temperature, whereas, the surfactant blend of IOSC15-18 and Alcohol Aloxy Sulphate (AAS) was resulted unstable. The solubility and chemical stability at high temperature and high salinity condition is improved by the blend of AOSC14-16+LMDO surfactant solution. This blend of surfactant solution will help for generating stable foam for gas mobility control in the methods of chemical Enhanced Oil Recovery (EOR).

An Optimized Experimental Investigation of Foam-Assisted N2 Huff-n-Puff Enhanced Oil Recovery in Fractured Shale Cores

2021 ◽  
Author(s):  
Xiaofei Xiong ◽  
James Jia Sheng
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Rapid Decline ◽  
Production Time ◽  
Experimental Conditions ◽  
Cycle Number ◽  
Injection Process ◽  
Matrix Permeability ◽  
Shale Reservoirs ◽  
Scale Matrix

Abstract Sustainable development of shale reservoirs and enhanced oil recovery have become a challenge for the oil industry in recent years. Shale reservoirs are typically characterized by nano Darcy-scale matrix, natural fractures, and artificially fractures with high permeability. Some of earlier studies have confirmed that gas huff-n-puff has been investigated and demonstrated as the most effective and promising solution for improving oil recovery in tight shale reservoirs with ultra-low permeability. Fractures provide an advantage in enhancing recovery from shale reservoirs but they also pose serious problems such as severe gas channeling, which led to rapid decline production from a single well. More studies are needed to optimize the process. This paper studies the method of foam-assisted N2 huff-n-puff to enhance oil recovery in fractured shale cores. The influence of foam on oil recovery was analyzed. The effect of matrix permeability, cycle number and production time on oil recovery are also considered. The shale core used in the experiment was from Sichuan Basin, China. For the purpose of comparation and validation, two groups of tests were conducted. One group of tests was N2 huff-n-puff, and the other was foam-N2 huff-n-puff. In the optimization experiment, matrix permeabilities were set as 0.01mD, 0.008mD and 0.001mD, cycle numbers ranged from one to five, the production time is designed to be 1 hour and 24 hours respectively. During the puff period of experiments, the history of oil recovery was closely monitored to reveal the mechanism. During a round of gas injection of fractured shale cores, foam-assisted N2 huff-n-puff oil recovery is 4.59%, which is significantly higher than that of N2 huff-n-puff is only 0.0126%, and the contrast becomes more obvious with the increase of matrix permeability. The results also showed that the cumulative oil recovery increased as the number of cycles was increased, with the same experimental conditions. There is an optimal production time to achieve maximum oil recovery. The cycle numbers, matrix permeability, and production time played important roles in foam-assisted N2 huff-n-puff injection process. Therefore, under certain conditions, foam-N2 huff-n-puff has a positive effect on oil development in fractured shale.

scholarly journals Molecular-Scale Considerations of Enhanced Oil Recovery in Shale

Energies ◽  
2020 ◽  
Vol 13 (24) ◽  
pp. 6619
Author(s):  
Mohamed Mehana ◽  
Qinjun Kang ◽  
Hari Viswanathan
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Energy Equation ◽  
Simulation Approach ◽  
Production Region ◽  
The World ◽  
Fluid Properties ◽  
Shale Reservoirs ◽  
Different Gases

With only less than 10% recovery, the primary production of hydrocarbon from shale reservoirs has redefined the energy equation in the world. Similar to conventional reservoirs, Enhanced Oil Recovery (EOR) techniques could be devised to enhance the current recovery factors. However, shale reservoirs possess unique characteristics that significantly affect the fluid properties. Therefore, we are adopting a molecular simulation approach that is well-suited to account for these effects to evaluate the performance of three different gases, methane, carbon dioxide and nitrogen, to recover the hydrocarbons from rough pore surfaces. Our hydrocarbon systems consists of either a single component (decane) or more than one component (decane and pentane). We simulated cases where concurrent and countercurrent displacement is studied. For concurrent displacement (injected fluids displace hydrocarbons towards the production region), we found that nitrogen and methane yielded similar recovery; however nitrogen exhibited a faster breakthrough. On the other hand, carbon dioxide was more effective in extracting the hydrocarbons when sufficient pressure was maintained. For countercurrent displacement (gases are injected and hydrocarbons are produced from the same direction), methane was found to be more effective, followed by carbon dioxide and nitrogen. In all cases, confinement reduced the recovery factor of all gases. This work provides insights to devise strategies to improve the current recovery factors observed in shale reservoirs.

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