Low-tension gas process in high-salinity and low-permeability reservoirs

Alolika Das,Quoc P Nguyen,Nhut Nguyen

doi:10.1007/s12182-020-00455-9

Alolika Das, Quoc P Nguyen + Show 1 more

Open Access

https://doi.org/10.1007/s12182-020-00455-9

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Journal: Petroleum Science	Publication Date: May 6, 2020
Citations: 7	License type: open-access

Affiliation: The University of Texas at Austin

Abstract

Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics.

Highlights

Conventional alkali–polymer (AP), surfactant–polymer (SP) and alkali–surfactant–polymer (ASP) flooding methods have limited success in carbonate formations because of typical high reservoir salinity, low permeability and complex rock–fluid interactions
The IFT measurements between oil and water for the extracted microemulsion phase are shown for the salinity range of 80,000–120,000 ppm, which corresponds to Type I environment (Fig. 2)
A surfactant formulation was designed using novel nonionic surfactant alkyl polyglucoside (APG) which exhibited ultra-low IFT, good aqueous stability and foam stabilization properties

Summary

Introduction

Conventional alkali–polymer (AP), surfactant–polymer (SP) and alkali–surfactant–polymer (ASP) flooding methods have limited success in carbonate formations because of typical high reservoir salinity, low permeability and complex rock–fluid interactions. Low-tension gas (LTG) flooding process replaces polymers with foam, typically generated with an injected gas such as nitrogen, CO2 or hydrocarbon gases. The process utilizes a low-injection-rate strategy to better suit the lowpermeability carbonate rocks. The surfactant is chosen such that it can simultaneously generate foam and lower the interfacial tension. The low-IFT surfactant reduces the interfacial tension between water and oil to low levels (less than 10−3 dyne/cm) and mobilizes residual oil after waterflood, whereas the foaming surfactant enhances propagation of foam that controls the mobility of the displacing phases (i.e., gas and surfactant solution) for better displacement efficiency.

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