Experimental Investigation of Alkaline/Surfactant/Polymer (ASP) Flooding in Low Permeability Heterogeneous Carbonate Reservoirs

2015 ◽  
Author(s):  
Shedid A. Shedid
Keyword(s):  
Experimental Investigation ◽  
Carbonate Reservoirs ◽  
Low Permeability ◽  
Asp Flooding ◽  
Alkaline Surfactant Polymer

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

A New Approach to ASP Flooding in High Saline and Hard Carbonate Reservoirs

2014 ◽  
Author(s):  
Shuaib Ahmed Kalwar ◽  
Khaled A Elraies ◽  
Muhammad Khan Memon ◽  
Sandeep Kumar ◽  
Ghulam Abbas ◽  
...  
Keyword(s):  
Carbonate Reservoirs ◽  
New Approach ◽  
Asp Flooding

scholarly journals Nonionic Surfactant to Enhance the Performances of Alkaline–Surfactant–Polymer Flooding with a Low Salinity Constraint

2020 ◽  
Vol 10 (11) ◽  
pp. 3752 ◽  
Author(s):  
Shabrina Sri Riswati ◽  
Wisup Bae ◽  
Changhyup Park ◽  
Asep K. Permadi ◽  
Adi Novriansyah
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Anionic Surfactant ◽  
Pore Volume ◽  
Salinity Gradient ◽  
Reference Case ◽  
Low Salinity ◽  
Asp Flooding ◽  
Optimum Salinity ◽  
Alkaline Surfactant Polymer

This paper presents a nonionic surfactant in the anionic surfactant pair (ternary mixture) that influences the hydrophobicity of the alkaline–surfactant–polymer (ASP) slug within low-salinity formation water, an environment that constrains optimal designs of the salinity gradient and phase types. The hydrophobicity effectively reduced the optimum salinity, but achieving as much by mixing various surfactants has been challenging. We conducted a phase behavior test and a coreflooding test, and the results prove the effectiveness of the nonionic surfactant in enlarging the chemical applicability by making ASP flooding more hydrophobic. The proposed ASP mixture consisted of 0.2 wt% sodium carbonate, 0.25 wt% anionic surfactant pair, and 0.2 wt% nonionic surfactant, and 0.15 wt% hydrolyzed polyacrylamide. The nonionic surfactant decreased the optimum salinity to 1.1 wt% NaCl compared to the 1.7 wt% NaCl of the reference case with heavy alcohol present instead of the nonionic surfactant. The coreflooding test confirmed the field applicability of the nonionic surfactant by recovering more oil, with the proposed scheme producing up to 74% of residual oil after extensive waterflooding compared to 51% of cumulative oil recovery with the reference case. The nonionic surfactant led to a Winsor type III microemulsion with a 0.85 pore volume while the reference case had a 0.50 pore volume. The nonionic surfactant made ASP flooding more hydrophobic, maintained a separate phase of the surfactant between the oil and aqueous phases to achieve ultra-low interfacial tension, and recovered the oil effectively.

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