Comparison of the effects of wettability alteration and IFT reduction on oil recovery in carbonate reservoirs

2012 ◽  
Vol 8 (1) ◽  
pp. 154-161 ◽  
Author(s):  
James J. Sheng
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration

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.

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 Experimental and modeling study of wettability alteration through seawater injection in limestone: a case study

2020 ◽  
Vol 17 (3) ◽  
pp. 749-758
Author(s):  
Omolbanin Seiedi ◽  
Mohammad Zahedzadeh ◽  
Emad Roayaei ◽  
Morteza Aminnaji ◽  
Hossein Fazeli
Keyword(s):  
Oil Recovery ◽  
Contact Angle Measurement ◽  
Angle Measurement ◽  
Carbonate Reservoirs ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Indirect Contact ◽  
Molecular Kinetic Theory ◽  
Wet Condition

AbstractWater flooding is widely applied for pressure maintenance or increasing the oil recovery of reservoirs. The heterogeneity and wettability of formation rocks strongly affect the oil recovery efficiency in carbonate reservoirs. During seawater injection in carbonate formations, the interactions between potential seawater ions and the carbonate rock at a high temperature can alter the wettability to a more water-wet condition. This paper studies the wettability of one of the Iranian carbonate reservoirs which has been under Persian Gulf seawater injection for more than 10 years. The wettability of the rock is determined by indirect contact angle measurement using Rise in Core technique. Further, the characterization of the rock surface is evaluated by molecular kinetic theory (MKT) modeling. The data obtained from experiments show that rocks are undergoing neutral wetting after the aging process. While the wettability of low permeable samples changes to be slightly water-wet, the wettability of the samples with higher permeability remains unchanged after soaking in seawater. Experimental data and MKT analysis indicate that wettability alteration of these carbonate rocks through prolonged seawater injection might be insignificant.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 767-783 ◽  
Author(s):  
C.. Qiao ◽  
L.. Li ◽  
R.T.. T. Johns ◽  
J.. Xu
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
Mechanistic Model ◽  
Contact Angles ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Physical Parameters ◽  
Minor Effect

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Flow Physics of Polymer Nanospheres and Diluted Microemulsion in Fractured Carbonate Reservoirs: An Investigation into Enhanced Oil Recovery Mechanisms

SPE Journal ◽  
2021 ◽  
pp. 1-14
Author(s):  
Hang Su ◽  
Fujian Zhou ◽  
Qing Wang ◽  
Fuwei Yu ◽  
Rencheng Dong ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Rate ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
Recovery Mechanisms ◽  
Polymer Nanospheres ◽  
Depth Propagation

Summary Enhanced oil recovery (EOR) in fractured carbonate reservoirs is challenging because of the heterogeneous and oil-wet nature. In this work, a new application of using polymer nanospheres (PNSs) and diluted microemulsion (DME) is presented to plug fractures and enhance water imbibition to recover oil from the tight, naturally fractured carbonate reservoirs. DME with different electric charges is compared through contact-angle and core-imbibition tests to evaluate their performances on EOR. The cationic DME is chosen because it has the fastest wettability-alteration rate and thus the highest oil recovery rate. Migration and plugging efficiency tests are conducted to identify the screened particle sizes of PNSs for the target reservoir cores. PNSs with a particle size of 300 nm are demonstrated to have the best performance of in-depth propagation before swelling and plugging after swelling within the naturally fractured cores are used in this study. Then coreflooding experiments are conducted to evaluate the EOR performance when PNSs and DME are used together, and results indicate that the oil recovery rate is increased by 24.3 and 44.1% compared to using PNSs or DME alone. In the end, a microfluidic experiment is carried out to reveal how DME works with PNSs.

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 Experimental investigation of chemical solutions effects on wettability alteration and interfacial tension reduction using nano-alkaline–surfactant fluid: an EOR application in carbonate reservoirs

2021 ◽  
Vol 11 (4) ◽  
pp. 1925-1941
Author(s):  
M. Sadegh Rajabi ◽  
Rasoul Moradi ◽  
Masoud Mehrizadeh
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Ammonium Bromide ◽  
Total Production ◽  
Thin Sections ◽  
Chemical Solutions

AbstractThe wettability preference of carbonate reservoirs is neutral-wet or oil-wet as the prevailing of hydrocarbon reserves that affects approximately half of the total production of hydrocarbons of the world. Therefore, due to surface wettability of carbonate rocks the notable fraction of oil is held inside their pores in comparison with sandstones. Since shifting the wettability preference toward water-wet system is of great interest, numerous components were used for this purpose. In this experimental research, the wettability alteration of dolomite surface by interacting with a novel nano-surfactant–alkaline fluid has been investigated in order to diminish its adhesion to crude oil droplets. The solutions were prepared by homogenous mixing of nanosilica particles with cetyl trimethyl ammonium bromide and sodium carbonate, respectively, as a cationic surfactant and alkaline agent. The maximum wettability alteration from oil-wet to water system was obtained by employing a mixture of nanoparticles in association with surfactant–alkaline. Then, the fluids were employed in core-surface from detached and attached forms to compare their interfacial effects on saturated thin sections by crude oil and to measure the wettability. In addition, the interfacial tension (IFT) between solutions and crude oil was investigated and the maximum IFT reduction was obtained from nano-surfactant. Finally, all chemical solutions were flooded to the dolomite plugs separately after water flooding in order to evaluate the maximum oil recovery factor acquired by nano-surfactant.

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