Wettability Alteration and Enhanced Oil Recovery Using Low Salinity Waterflooding in Limestone Rocks: A Mechanistic Study

2018 ◽  
Author(s):  
Joel Tetteh ◽  
Nazirah Mohd Janjang ◽  
Reza Barati
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Mechanistic Study ◽  
Low Salinity ◽  
Low Salinity Waterflooding

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.

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

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.

A Magnetic Resonance Study of Low Salinity Waterflooding for Enhanced Oil Recovery

2017 ◽  
Vol 31 (10) ◽  
pp. 10802-10811 ◽  
Author(s):  
Ming Li ◽  
Sarah Vashaee ◽  
Laura Romero-Zerón ◽  
Florin Marica ◽  
Bruce J. Balcom
Keyword(s):  
Magnetic Resonance ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Magnetic Resonance Study ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Newly Prepared Nano Gamma Alumina and Its Application in Enhanced Oil Recovery: An Approach to Low-Salinity Waterflooding

2016 ◽  
Vol 30 (5) ◽  
pp. 3791-3797 ◽  
Author(s):  
Sajad Kiani ◽  
Mostafa Mansouri Zadeh ◽  
Saeed Khodabakhshi ◽  
Alimorad Rashidi ◽  
Jamshid Moghadasi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gamma Alumina ◽  
Low Salinity ◽  
Low Salinity Waterflooding

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.

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.

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