Potential of Low-Salinity Waterflood To Improve Oil Recovery in Carbonates: Demonstrating the Effect by Qualitative Coreflood

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1643-1654 ◽  
Author(s):  
Ramez A. Nasralla ◽  
Ekaterina Sergienko ◽  
Shehadeh K. Masalmeh ◽  
Hilbert A. van der Linde ◽  
Niels J. Brussee ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Experimental Approach ◽  
Geochemical Modeling ◽  
Middle Eastern ◽  
Carbonate Reservoirs ◽  
Rock Properties ◽  
Improved Oil Recovery ◽  
Calcite Dissolution ◽  
Low Salinity ◽  
Reservoir Conditions

Summary Low-salinity waterflood (LSF) is a promising improved-oil-recovery (IOR) technology. Although, it was demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established because only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil-recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater (SW) and several dilutions of formation brine and SW were flooded in the tertiary mode to evaluate their impacts on oil recovery compared with formation-brine injection. In addition, a geochemical study was performed with PHREEQC software (Parkhurst and Appelo 1999) to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability toward more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, SW is more-favorable for improved oil recovery than formation brine because injection of SW after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite on the basis of the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that LSF has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most-influential parameters affecting LSF response.

scholarly journals Comprehensive investigation of low salinity waterflooding in carbonate reservoirs

2021 ◽  
Author(s):  
M. Fouad Snosy ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
Helmy Sayyouh
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Rock Properties ◽  
Recovery Stage ◽  
Low Salinity ◽  
Water Composition ◽  
Secondary Recovery ◽  
Low Salinity Waterflooding ◽  
Tertiary Recovery ◽  
Incremental Oil Recovery

AbstractWaterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.

scholarly journals The effect of carbonate rock wettability on the performance of low salinity waterflooding: an experimental approach

2021 ◽  
Author(s):  
Abdulrazag Zekri ◽  
Hildah Nantongo ◽  
Fathi Boukadi
Keyword(s):  
Oil Recovery ◽  
Experimental Approach ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Main Research ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Conditions ◽  
Salinity Water

AbstractWhile the “low salinity waterflooding” (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a “base water”. Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil-wet and intermediate-wettability systems. Sequential flooding consisting of seawater followed by diluted seawater in a water-wet system yielded the highest DE of 88%. Besides, low-salinity brine followed by sulfate performed better in a water-wet environment than in oil- and intermediate-wettability systems.

Continental-shelf freshwater water resources and improved oil recovery by low-salinity waterflooding

AAPG Bulletin ◽  
2017 ◽  
Vol 101 (01) ◽  
pp. 1-18 ◽  
Author(s):  
Mark Person ◽  
John L. Wilson ◽  
Norman Morrow ◽  
Vincent E.A. Post
Keyword(s):  
Water Resources ◽  
Continental Shelf ◽  
Oil Recovery ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Improved Oil Recovery in Fractured Carbonate Reservoirs: Don't Give Induced Fractures A Chance!

2006 ◽  
Author(s):  
Dick Jacob Ligthelm ◽  
Paul Jacob van den Hoek ◽  
Pascal Hos ◽  
Marinus J. Faber ◽  
Roeland Roeterdink
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Improved Oil Recovery ◽  
Fractured Carbonate ◽  
Induced Fractures

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Yaoze Cheng ◽  
Yin Zhang ◽  
Abhijit Dandekar ◽  
Jiawei Li
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Viscosity Reduction ◽  
Displacement Efficiency ◽  
Natural Sand ◽  
Ζ Potential ◽  
Low Salinity ◽  
Viscous Oil ◽  
Reservoir Conditions ◽  
Salinity Water

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

Geochemical Modeling on Effect of Active Species, Ca2+, Mg2+ and SO2-4 on the Carbonate Rock Surface, in Connection to Wettability Alteration of the Rock

2021 ◽  
Author(s):  
Mohamed Ibrahim Mohamed ◽  
Vladimir Alvarado
Keyword(s):  
Contact Angle ◽  
Surface Charge ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Rock Properties ◽  
Carboxyl Group ◽  
Geochemical Model ◽  
Positively Charged

Abstract A large percentage of petroleum reserves are located in carbonate reservoirs, which can be divided into limestone, chalk and dolomite. Roughly the oil recovery from carbonates is below the 30% due to the strong oil wetness, low permeability, abundance of natural fractures, and inhomogeneous rock properties Austad (2013). Injection of adjusted brine chemistry into carbonate reservoirs has been reported to increase oil recovery by 5-30% of the original oil in place in field tests and core flooding experiments. Previous studies have shown that adjusted waterflooding recovery in carbonate reservoirs is dependent on the composition and ionic strength of the injection brine (Morrow et al. 1998; Zhang 2005). Many research works have focused on the role of the brine composition in altering the initial wettability state of carbonate rock, which is usually intermediate- to oil-wet. Crude oils contain carboxyl group, -COOH, that can be found in the resin and asphaltenes fractions. The negatively charged carboxyl group, -COOH bond very strongly with the positively charged, sites on the carbonate surface. The carbonate surface, which is positively charged is believed to adsorb the SO42− that is negatively charged. On the other side cations Ca2+ and Mg2+ bind to the negatively charged carboxylic group and release it from the surface. In this study we use a closed system geochemical model to study the effect of the surface-charge dominant species; Ca2+, Mg2+ and SO42− on the carbonate surfaces at 80 °C. The proposed geochemical interactions can possibly lead to a change in the surface charge, altering wettability of the rock by exchanging ions/cations. Brines with various concentrations of Mg2+ and SO42− were prepared in the lab and contact angle between carbonate substrate and crude oil was measured using a rising/captive bubble tensiometer at 80 °C. The composition of the carbonate system was collected from previous literature review and the composition of adjusted brines was used to build a surface sorption database to develop a geochemical model. This model is focused on identifying the reaction paths and the surface behavior that may represent the real system. Changes in carbonate surface wettability were further evaluated using a series of contact angle experiments. Experimental observations and modeling results are concordant and imply that SO42− ions may alter the wettability of carbonate surface at high temperature.

scholarly journals A mechanistic investigation of low salinity water flooding coupled with ion tuning for enhanced oil recovery

RSC Advances ◽  
2020 ◽  
Vol 10 (69) ◽  
pp. 42570-42583
Author(s):  
Rohit Kumar Saw ◽  
Ajay Mandal
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Calcite Dissolution ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Mechanistic Investigation ◽  
Salinity Water

The combined effects of dilution and ion tuning of seawater for enhanced oil recovery from carbonate reservoirs. Dominating mechanisms are calcite dissolution and the interplay of potential determining ions that lead to wettability alteration of rock surface.

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