Imbibition of Sulfate and Magnesium Ions into Carbonate Rocks at Elevated Temperatures and Their Influence on Wettability Alteration and Oil Recovery

2007 ◽  
Vol 21 (4) ◽  
pp. 2138-2146 ◽  
Author(s):  
Omid Karoussi ◽  
Aly A. Hamouda
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Elevated Temperatures ◽  
Wettability Alteration ◽  
Magnesium Ions

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.

scholarly journals Alteration wettability of carbonate rocks by Nano fluids and comparison with PEG and SDS

2020 ◽  
Vol 10 (4) ◽  
pp. 54-68
Author(s):  
Dr. Rana R Jalil ◽  
Dr. Hussein Qasim Hussein
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Saline Water ◽  
Sodium Dodecyl ◽  
Silica Nanoparticle ◽  
Wettability Alteration ◽  
Limestone Rock ◽  
The Stability ◽  
Enhance Oil Recovery ◽  
Sds Surfactant

This work was conducted to study limestone rock wettability alteration to enhance oil recovery by flooding using different Nano silica (NS) sizes suspended in saline water and compared with flooding solution of polyethylene glycol (PEG) polymer and sodium dodecyl sulfate (SDS) surfactant, the stability of nanofluids measured by zeta potential. In the flooding system, the secondary recovery by silica nanofluids (0.01 wt. % NS concentration) achieved an oil recovery of 35vol. % and 26.08 vol. % for 10, 52 nm after primary recovery respectively, while PEG polymer and SDS surfactant achieved oil recovery of 5 vol. % and 10 vol. % only respectively. The stability of pressure difference approved that silica nanoparticle never causes any plug or damage for the carbonate rocks

scholarly journals  Brine-Dependent Recovery Processes (Smart-Water/Low-Salinity-Water) in Carbonate and Sandstone Petroleum Reservoirs: Review of Laboratory-Field Studies, Interfacial Mechanisms and Modeling Attempts

2018 ◽  
Author(s):  
Adedapo N. Awolayo ◽  
Hemanta K. Sarma ◽  
Long X. Nghiem
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Ionic Composition ◽  
Recovery Process ◽  
Field Studies ◽  
Field Trials ◽  
Research Area ◽  
Wettability Alteration ◽  
Smart Water ◽  
Underlying Mechanisms

Brine-dependent recovery process has seen much global research efforts in the past two decades because of their benefits over other oil recovery methods. The process involves the tweaking of the ionic composition and strength of the injected water to improve oil production. In recent years, several studies ranging from laboratory coreflood experiments by many researchers to field trials by several companies admit to the potential of recovering additional oil in sandstone and carbonate reservoirs. Sandstone and carbonate rocks are composed of completely different minerals, with varying degree of complexity and heterogeneity, but wettability alteration has been widely considered as the consequence rather than the cause of brine-dependent recovery. However, there is no consensus on the cause as several mechanisms have been proposed to relate the wettability changes to the improved recovery. This review paper aims to provide a state-of-the-art development in published research and various efforts of the industry. This review outlines an overview of laboratory and field observations, descriptions of underlying mechanisms and their validity, the complexity of the oil-brine-rock interactions, modelling works, and comparison between sandstone and carbonate rocks. The provided information is intended to provide the reader with up-to-date information, point to relevant studies for those who are new and those implementing either laboratory- or field-scale projects to speed up the process of further investigations in this research area. Overall, the outcome of this review would potentially be of immense benefit to the oil industry.

scholarly journals Brine-Dependent Recovery Processes in Carbonate and Sandstone Petroleum Reservoirs: Review of Laboratory-Field Studies, Interfacial Mechanisms and Modeling Attempts

Energies ◽  
2018 ◽  
Vol 11 (11) ◽  
pp. 3020 ◽  
Author(s):  
Adedapo Awolayo ◽  
Hemanta Sarma ◽  
Long Nghiem
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Ionic Composition ◽  
Field Studies ◽  
Field Trials ◽  
Process Efficiency ◽  
Wettability Alteration ◽  
Recovery Processes ◽  
Composition Modification ◽  
Underlying Mechanisms

Brine-dependent recovery, which involves injected water ionic composition and strength, has seen much global research efforts in the past two decades because of its benefits over other oil recovery methods. Several studies, ranging from lab coreflood experiments to field trials, indicate the potential of recovering additional oil in sandstone and carbonate reservoirs. Sandstone and carbonate rocks are composed of completely different minerals, with varying degree of complexity and heterogeneity, but wettability alteration has been widely considered as the consequence rather than the cause of brine-dependent recovery. However, the probable cause appears to be as a result of the combination of several proposed mechanisms that relate the wettability changes to the improved recovery. This paper provides a comprehensive review on laboratory and field observations, descriptions of underlying mechanisms and their validity, the complexity of the oil-brine-rock interactions, modeling works, and comparison between sandstone and carbonate rocks. The improvement in oil recovery varies depending on brine content (connate and injected), rock mineralogy, oil type and structure, and temperature. The brine ionic strength and composition modification are the two major frontlines that have been well-exploited, while further areas of investigation are highlighted to speed up the interpretation and prediction of the process efficiency.

A Fundamental Model for Predicting Oil Recovery Due to Low Salinity Water Injection in Carbonate Rocks

2014 ◽  
Author(s):  
E. W. Al-Shalabi ◽  
K.. Sepehrnoori ◽  
G.. Pope ◽  
K.. Mohanty
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Water Injection ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Fundamental Model ◽  
Low Salinity Water ◽  
Proposed Model ◽  
Salinity Water ◽  
Low Salinity Water Injection

Abstract The low salinity water injection (LSWI) technique is gaining popularity due to the simplicity of the method compared to other thermal and chemical EOR techniques. In this paper, a fundamental model is proposed which captures the effect of LSWI on improving the microscopic displacement efficiency from carbonates through the trapping number. The proposed model was used to history match recently published corefloods using the UTCHEM simulator. The proposed model incorporates wettability alteration effect through contact angle and trapping parameter. Results showed that history matching of the corefloods was performed successfully using the proposed model. Moreover, wettability alteration is the main contributor to LSWI effect on oil recovery from carbonate rocks. The proposed model was further validated upon which the applicability is extended to include weakly-oil-wet to mixed-wet rocks. This model can be used for oil recovery predictions from carbonate rocks at the field-scale.

scholarly journals Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks

2019 ◽  
Vol 2 (2) ◽  
pp. 7-8
Author(s):  
Madison Barth ◽  
Japan Trivedi ◽  
Benedicta Nwani ◽  
Yosamin Esanullah
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Surfactant Concentration ◽  
Wettability Alteration ◽  
Ionic Surfactant ◽  
Improved Oil Recovery ◽  
Fluid Analysis ◽  
Tertiary Recovery ◽  
Brine Salinity

Of recent, there has been research and development in the technologies/techniques required to meet the ever-growing energy demand in the world. Oil is a major source of energy which is contained in over 50% of carbonate reservoirs. The oil/mixed wettability of carbonate rocks makes it technically challenging to recover the needed oil. The process of crude oil recovery has three different stages primary, secondary and tertiary recovery. Tertiary recovery is also known as enhanced oil recovery or EOR. EOR includes the use of surfactants to reduce the interfacial tension between a hydrocarbon and brine, thus suspending them both in a microemulsion. Surfactant performance can be affected by multiple variables, including brine salinity, surfactant concentration, and type of hydrocarbon. A petroleum engineer must take all variables into consideration when selecting a surfactant to make sure that its efficiency is as high as possible, especially because the use of surfactants is costly.  In this work, a chembetaine zwitter ionic surfactant of two different concentrations are evaluated at various synthetic formation brine salinities for their favourable wettability alteration and interfacial tension reduction in oil-wet carbonate- Silurian Dolomite. For the evaluation, fluid-fluid and rock-fluid analysis are carried out to select the optimal surfactant concentration and brine salinity with the greatest improved oil recovery potential.  Results are indicative that the surfactant at the two concentrations studied is compatible at the ranges of salinities evaluated. However, from the fluid-fluid analysis, there was no ultra-low interfacial tension that is needed for oil mobilization. More so, the rock-fluid analysis shows that the surfactant is not able to alter the wettability of oil-wet rocks favourably. The optimal surfactant slug for the greatest oil recovery, in this case, would be expected at 0.5% surfactant concentration in 10,000 ppm synthetic formation brine salinity. This study, therefore, serves as a guide for the design of optimal surfactant slug in oil-wet carbonate cores requires to reduce non-productive time, prevent reservoir damage and therefore improve recovery.

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