scholarly journals Effect of viscosity and interfacial tension of surfactant–polymer flooding on oil recovery in high-temperature and high-salinity reservoirs

2013 ◽  
Vol 4 (1) ◽  
pp. 9-16 ◽  
Author(s):  
Zhiwei Wu ◽  
Xiang’an Yue ◽  
Tao Cheng ◽  
Jie Yu ◽  
Heng Yang
Keyword(s):  
High Temperature ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
High Salinity ◽  
Polymer Flooding

Experimental Study on Low Interfacial Tension Foam for Enhanced Oil Recovery in High-Temperature and High-Salinity Reservoirs

2017 ◽  
Vol 31 (12) ◽  
pp. 13416-13426 ◽  
Author(s):  
Jiaping Tao ◽  
Caili Dai ◽  
Wanli Kang ◽  
Guang Zhao ◽  
Yifei Liu ◽  
...  
Keyword(s):  
Experimental Study ◽  
High Temperature ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
High Salinity ◽  
Low Interfacial Tension

scholarly journals NEW AQUEOUS POLYMER FOR HIGH-TEMPERATURE RESERVOIRS

2018 ◽  
Vol 15 (30) ◽  
pp. 380-386
Author(s):  
Y. V. SAVINYKH ◽  
L. D. LANG
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
High Salinity ◽  
Sea Water ◽  
Polymer Flooding ◽  
Water Soluble ◽  
Water Flooding ◽  
Polymer Gel ◽  
Sweep Efficiency ◽  
Water Soluble Polymer

Polymer flooding is technologically simple and highly effective method of enhanced oil recovery. The method is based on adding a small amount of polymer in conventional water flooding of oil reservoirs. The increase in viscosity and the reduction of the mobility of injected water are to equalize the displacement front by slowing the moving of water in the highly permeable zones and restricting the formation of water finger. These factors help to increase the sweep efficiency and oil-water displacement efficiency during flooding. Polymer flooding has been used successfully in clastic and carbonate reservoirs, as well as in low-permeability reservoirs such as a fractured basement. However, most of the current polymer gel used for control water flows are decayed by a high content of ions Ca2+ and Mg2+ in formation water or in injected water. Similarly, polymer gels lose their stability at high reservoir temperature (above 70°C). Developing water-soluble polymer, which does not change their rheological properties under high salinity and high temperature (over 100°C), is very important when producing offshore, where sea water is commonly used for flooding (high salinity of 30-40 g/L).

scholarly journals Modification of Xanthan Gum for a High-Temperature and High-Salinity Reservoir

Polymers ◽  
2021 ◽  
Vol 13 (23) ◽  
pp. 4212
Author(s):  
Mohamed Said ◽  
Bashirul Haq ◽  
Dhafer Al Shehri ◽  
Mohammad Mizanur Rahman ◽  
Nasiru Salahu Muhammed ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Xanthan Gum ◽  
Elevated Temperatures ◽  
High Salinity ◽  
Residual Oil ◽  
Core Flooding ◽  
Nacl Solution ◽  
The Core ◽  
Tertiary Oil Recovery

Tertiary oil recovery, commonly known as enhanced oil recovery (EOR), is performed when secondary recovery is no longer economically viable. Polymer flooding is one of the EOR methods that improves the viscosity of injected water and boosts oil recovery. Xanthan gum is a relatively cheap biopolymer and is suitable for oil recovery at limited temperatures and salinities. This work aims to modify xanthan gum to improve its viscosity for high-temperature and high-salinity reservoirs. The xanthan gum was reacted with acrylic acid in the presence of a catalyst in order to form xanthan acrylate. The chemical structure of the xanthan acrylate was verified by FT-IR and NMR analysis. The discovery hybrid rheometer (DHR) confirmed that the viscosity of the modified xanthan gum was improved at elevated temperatures, which was reflected in the core flood experiment. Two core flooding experiments were conducted using six-inch sandstone core plugs and Arabian light crude oil. The first formulation—the xanthan gum with 3% NaCl solution—recovered 14% of the residual oil from the core. In contrast, the modified xanthan gum with 3% NaCl solution recovered about 19% of the residual oil, which was 5% higher than the original xanthan gum. The xanthan gum acrylate is therefore more effective at boosting tertiary oil recovery in the sandstone core.

Water-Flooding Fluid Diversion Copolymeric Microsphere Prepared by Inverse Suspension Polymerization

e-Polymers ◽  
2007 ◽  
Vol 7 (1) ◽  
Author(s):  
Huang Zhiyu ◽  
Lu Hongsheng ◽  
Zhang Tailiang
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Oil Recovery ◽  
High Salinity ◽  
Suspension Polymerization ◽  
Oil Reservoirs ◽  
Water Flooding ◽  
Toughness Index ◽  
Inverse Suspension Polymerization ◽  
Enhance Oil Recovery

Abstract In order to enhance oil recovery in high-temperature and high-salinity oil reservoirs, the copolymeric microspheres containing acrylamide (AM), acrylonitrile (AN) and AMPS was synthesized by inverse suspension polymerization. The copolymeric microsphere was very uniform and the size could be changed according to the condition of polymerization. The lab-scale studies showed that the copolymeric microsphere exhibit good salt-tolerance and thermal-stability when immersed in 20×105 mg/L NaCl(or KCl) solution, 7500 mg/L CaCl2 (or MgCl2) solution or 2000 mg/L FeCl3 solution, respectively. The copolymeric microsphere showed satisfactory absorbency rates. The sand-pipes experiments confirmed that the average toughness index was 1.059. It could enhance the oil recovery by about 3% compared with the corresponding irregular copolymeric particle.

Enhancing Heavy-Oil-Recovery Efficiency by Combining Low-Salinity-Water and Polymer Flooding

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Yang Zhao ◽  
Shize Yin ◽  
Randall S. Seright ◽  
Samson Ning ◽  
Yin Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Salinity ◽  
Polymer Flooding ◽  
Heavy Oil Recovery ◽  
Sweep Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Increased Oil Recovery

Summary Combining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing heavy-oil recovery.

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