Surfactant-Aided Low-Salinity Waterflooding for Low-Temperature Carbonate Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Yue Shi ◽  
Chammi Miller ◽  
Kishore Mohanty
Keyword(s):  
Low Temperature ◽  
Oil Recovery ◽  
Anionic Surfactants ◽  
Surfactant Solution ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Original Oil In Place

Summary Carbonate reservoirs tend to be oil-wet/mixed-wet and heterogeneous because of mineralogy and diagenesis. The objective of this study is to improve oil recovery in low-temperature dolomite reservoirs using low-salinity and surfactant-aided spontaneous imbibition. The low-salinity brine composition was optimized using ζ-potential measurements, contact-angle (CA) experiments, and a novel wettability-alteration measure. Significant wettability alteration was observed on dolomite rocks at a salinity of 2,500 ppm. We evaluated 37 surfactants by performing CA, interfacial-tension (IFT), and spontaneous-imbibition experiments. Three (quaternary ammonium) cationic and one (sulfonate) anionic surfactants showed significant wettability alteration and produced 43–63% of original oil in place (OOIP) by spontaneous imbibition. At a low temperature (35°C), oil recovery by low-salinity effect is small compared with that by wettability-altering surfactants. Coreflood tests were performed with a selected low-salinity cationic surfactant solution. A novel coreflood was proposed that modeled heterogeneity and dynamic imbibition into low-permeability regions. The results of the “heterogeneous” coreflood were consistent with that of spontaneous-imbibition tests. These experiments demonstrated that a combination of low-salinity brine and surfactants can make originally oil-wet dolomite rocks more water-wet and improve oil recovery from regions bypassed by waterflood at a low temperature of 35°C.

scholarly journals Effect of salinity on oil production: review on low salinity waterflooding mechanisms and exploratory study on pipeline scaling

2020 ◽  
Vol 75 ◽  
pp. 50 ◽  
Author(s):  
Tao Zhang ◽  
Yiteng Li ◽  
Chenguang Li ◽  
Shuyu Sun
Keyword(s):  
Oil Recovery ◽  
Rapid Development ◽  
Preliminary Investigation ◽  
Petroleum Industry ◽  
Phase Field Model ◽  
Scale Formation ◽  
Wettability Alteration ◽  
Reservoir Properties ◽  
Low Salinity ◽  
Low Salinity Waterflooding

The past decades have witnessed a rapid development of enhanced oil recovery techniques, among which the effect of salinity has become a very attractive topic due to its significant advantages on environmental protection and economical benefits. Numerous studies have been reported focusing on analysis of the mechanisms behind low salinity waterflooding in order to better design the injected salinity under various working conditions and reservoir properties. However, the effect of injection salinity on pipeline scaling has not been widely studied, but this mechanism is important to gathering, transportation and storage for petroleum industry. In this paper, an exhaustive literature review is conducted to summarize several well-recognized and widely accepted mechanisms, including fine migration, wettability alteration, double layer expansion, and multicomponent ion exchange. These mechanisms can be correlated with each other, and certain combined effects may be defined as other mechanisms. In order to mathematically model and numerically describe the fluid behaviors in injection pipelines considering injection salinity, an exploratory phase-field model is presented to simulate the multiphase flow in injection pipeline where scale formation may take place. The effect of injection salinity is represented by the scaling tendency to describe the possibility of scale formation when the scaling species are attached to the scaled structure. It can be easily referred from the simulation result that flow and scaling conditions are significantly affected if a salinity-dependent scaling tendency is considered. Thus, this mechanism should be taken into account in the design of injection process if a sustainable exploitation technique is applied by using purified production water as injection fluid. Finally, remarks and suggestions are provided based on our extensive review and preliminary investigation, to help inspire the future discussions.

Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

2021 ◽  
pp. 1-18
Author(s):  
Takaaki Uetani ◽  
Hiromi Kaido ◽  
Hideharu Yonebayashi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Oil Composition ◽  
Total Acid ◽  
Low Salinity ◽  
Total Acid Number

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

scholarly journals Enhanced oil recovery from carbonate reservoirs by spontaneous imbibition of low salinity water

2018 ◽  
Vol 15 (3) ◽  
pp. 564-576 ◽  
Author(s):  
Mohammad Reza Zaeri ◽  
Rohallah Hashemi ◽  
Hamidreza Shahverdi ◽  
Mehdi Sadeghi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

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.

Pore-Scale Imaging of Tertiary Low Salinity Waterflooding in a Heterogeneous Carbonate Rock at Reservoir Conditions

2021 ◽  
Author(s):  
Ahmed M. Selem ◽  
Nicolas Agenet ◽  
Martin J. Blunt ◽  
Branko Bijeljic
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
High Salinity ◽  
Wettability Alteration ◽  
Micro Ct ◽  
Pore Scale ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Fluid Configuration

Abstract We investigated pore-scale oil displacement and rock wettability in tertiary low salinity waterflooding (LSW) in a heterogeneous carbonate sample using high-resolution three-dimensional imaging. This enabled the underlying mechanisms of the low salinity effect (LSE) to be observed and quantified in terms of changes in wettability and pore-scale fluid configuration, while also measuring the overall effect on recovery. The results were compared to the behavior under high salinity waterflooding (HSW). To achieve the wetting state found in oil reservoirs, an Estaillades limestone core sample was aged at 11 MPa and 80°C for threeweeks. The moderately oil-wet sample was then injected with high salinity brine (HSB) at a range of increasing flow rates, namely at 1, 2,4, 11, 22 and 42 µL/min with 10 pore volumes injected at each rate.Subsequently, low salinity brine (LSB) was injected following the same procedure. X-ray micro-computed tomography (micro-CT) was usedto visualize the fluid configuration in the pore space.A total of eight micro-CT images, with a resolution of 2.3 µm/voxel, wereacquired after both low salinity and high salinity floods.These high-resolution images were used to monitor fluid configuration in the porespace and obtain fluid saturations and occupancy maps. Wettabilitywascharacterized by measurements of in situ contactanglesand curvatures. The results show that the pore-scale mechanisms of improved recovery in LSW are consistent with the development of water micro-dropletswithin the oil and the expansion of thin water films between the oil and rock surface. Before waterflooding and during HSW, the measured contact angles were constant and above 110°, while the meancurvature and the capillary pressure values remained negative, suggesting that the HSB did not change the wettability state of the rock. However, with LSW the capillary pressure increased towards positive values as the wettability shifted towards a mixed-wet state. The fluidoccupancy analysis reveals a salinity-induced change in fluid configuration in the pore space. HSB invaded mainly the larger pores and throats, but with LSW brine invaded small-size pores and throats.Overall,our analysis shows that a change from a weakly oil-wet towards a mixed-wet state was observed mainly after LSW, leading to an incremental increase in oil recovery. This work established a combined coreflooding and imaging methodology to investigate pore-scale mechanisms and wettability alteration for tertiary LSW in carbonates.It improves our understanding of LSW asan enhanced oil recovery (EOR) method for potential field-scale applications. The data provides a valuable benchmark for pore-scale modelling as well as an insight into how even modest wettability changes can lead to additional oil recovery.

Osmosis as Mechanism for Low-Salinity Enhanced Oil Recovery

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1227-1235 ◽  
Author(s):  
K.. Sandengen ◽  
A.. Kristoffersen ◽  
K.. Melhuus ◽  
L. O. Jøsang
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Salinity Gradient ◽  
Spontaneous Imbibition ◽  
Model Systems ◽  
Wettability Alteration ◽  
Connate Water ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Summary We believe that osmosis has been overlooked as a possible mechanism for observed low-salinity enhanced-oil-recovery (EOR) effects. Osmosis can occur in an oil/water/rock system when injecting low-salinity water, because the system is full of an excellent semipermeable membrane—the oil itself. In the present work, water transport through oil films was visualized both in 2D micromodels and in sandstone cores imaged in a microcomputed tomography (CT). After treating these model systems with hexamethyldisilazane (HMDS) to render them more oil-wet, water became discontinuous, and it was possible to establish osmotic gradients. Either expansion or contraction of the connate water was observed, depending on the direction of the imposed salinity gradient. Because osmosis could be the underlying mechanism for low-salinity EOR, two changes in research strategy are proposed: Most importantly, the use of spontaneous-imbibition tests as evidence for wettability alteration in low-salinity water should be critically reinvestigated. This is because observed production could have stemmed from “osmotic expansion” of the connate water rather than wettability change. Second, much research focus should be shifted from sandstone reservoirs to fractured oil-wet carbonates. Osmosis potentially yields larger responses for the latter reservoir type, whereas from a mechanistic perspective the reason behind low-salinity EOR functioning in both sandstones and carbonates deserves further attention.

scholarly journals Spontaneous Imbibition Test of Low Salinity Injection at Low Saline Waxy Crude Carbonate

2018 ◽  
Vol 7 (2) ◽  
pp. 14-22 ◽  
Author(s):  
Fiki Hidayat ◽  
Tomi Erfando ◽  
Borry Frima Maulana
Keyword(s):  
Oil Recovery ◽  
Ph Effect ◽  
Spontaneous Imbibition ◽  
Salt Composition ◽  
Low Salinity ◽  
Effect Mechanism ◽  
The North ◽  
Low Salinity Waterflooding ◽  
The North Sea ◽  
Paraffinic Crude

Low salinity waterflooding (LSW) is categorized as one of emerging EOR technologies. It is done by injecting water with different salt composition and/or concentration. The research has been carried out for both sandstone and carbonate with the results looks promising. However, most of this research still concentrated in the north sea, middle east and North America region. This article discusses the applicability of low salinity waterflooding methodology in Indonesia. Spontaneous imbibition test is carried out to observe the recovery gain from a various combination of concentration and composition of the injected brine. The change of pH of the brine is also examined in order to confirm the pH effect mechanism. Three different concentration of brine (500 ppm, 5.000 ppm, and 10.000 ppm), three different brine composition (NaCl, CaCl2, and MgCl2) and high paraffinic crude oil are used as the fluid sample. It is found that the increased oil recovery is significant at a salinity of 10,000 ppm for MgCl2 and 5,000 ppm for NaCl ions. While the lowest recovery was shown by the test at a salinity of 500 ppm

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