Enhanced oil recovery using low tension gas flooding in high salinity, low permeability carbonate reservoirs

Date

2018-12

Authors

Das, Alolika

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Abstract

Chemical enhanced oil recovery (EOR) in carbonate reservoirs is a technically and economically challenging process. Low-Tension Gas flooding is developed as an attractive alternative to conventional EOR methods for application in low permeability and high salinity formations, especially in the presence of divalent cations. The process of Low-Tension Gas (LTG) flooding has been investigated on the laboratory scale as a tertiary and secondary recovery process for a low permeability (<10 mD) Middle Eastern carbonate reservoir with high formation salinity (~200,000 ppm TDS; 19,000 ppm of Ca ²⁺ and Mg ²⁺). LTG flooding design is based on two main mechanisms: mobilizing residual oil by generating ultra-low interfacial tension (IFT) conditions in the reservoir between oil and water, and efficient displacement of the mobilized oil by using foam as a mobility control agent. A novel surfactant formulation using non-ionic alkyl-polyglucoside (APG), anionic ethoxylated propoxylated carboxylate and internal olefin sulfonate (IOS) was developed which could generate ultra-low IFT, show good aqueous stability, fast equilibration, low microemulsion viscosity and support foam stability in presence of the high salinity formation brine. Microemulsion properties were studied to understand the interaction between microemulsion and foam stability at a microscopic scale. Measured oil-water IFT values for Type I microemulsion were as low as 10 ⁻³ dyne/cm, indicating an efficient formulation for oil mobilization. In the Type I microemulsion range, increase in salinity was observed to comparatively lower the foam stability. Measurement of micelle diameter and concentration showed that increase in salinity led to increase in volume of solubilized oil and increased size of oil-swollen micelles. The reduced inter-micellar repulsion because of larger, disperse oil-swollen micelles decreased the ordered structuring of micelles necessary for the stepwise thinning of film lamellae, which reduced the foam stability. LTG flooding strategy for tertiary oil recovery (post waterflood) was then investigated in coreflood experiments through co-injection of surfactant solution and gas (N2). The effect of injection parameters such as surfactant concentration, injected gas fraction (foam quality), drive composition and injected slug salinity on oil recovery and foam stability and hence mobility control (between displacing phase and oil) was examined. Results indicate oil recovery of over 80% ROIP (residual oil in place after waterflood) and 50% OOIP (original oil in place) with residual oil after LTG flooding (SorLTG) around 6%. This proves that the LTG flooding process exhibits favorable mobilization and displacement of residual oil. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough, effluent salinity and pressure drop characteristics. The high cost of chemicals and/or the limited supply of gas can make this process economically challenging. Injection strategy for tertiary oil recovery was optimized such that the oil recovery can be maximized using a minimum amount of the injected gas and the surfactant, thereby ensuring a more economically-viable recovery process. Surfactant injection strategy was optimized by varying the concentration and pore volumes of the surfactant slug injected. Nitrogen gas was co-injected during select time periods throughout the entire chemical injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% by inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual dynamic adsorption data for each of the three classes of surfactants used. Finally, the inter-relation between injected foam quality, in-situ gas saturation, pressure gradient and oil recovery were examined using Computed-Tomography (CT) scans during coreflooding experiments. The scope of applicability of LTG flooding was then extended to secondary oil recovery under the same reservoir conditions. Secondary recovery using LTG flooding was compared to conventional secondary recovery methods such as waterflooding. Oil recovery was observed to increase by 16% OOIP (Original Oil in Place) as compared to waterflooding, even in case of micellar flooding without gas. On introducing mobility control during LTG flooding in the form of injected gas, the secondary oil recovery was observed to increase steadily up to 81% OOIP. Co-injecting gas and surfactant also exhibited lower pressure drop than waterflood, thus underlining the importance and efficiency of mobility control using foam in secondary recovery. Gas injection strategy was optimized in terms of injected foam quality and onset of gas injection. Chemical injection strategy was also modified to test the impact of different in-situ salinity profiles on oil recovery

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