Mechanistic Modeling of Low-Salinity Waterflooding Through Coupling a Geochemical Package With a Compositional Reservoir Simulator

2016 ◽  
Vol 19 (01) ◽  
pp. 142-162 ◽  
Author(s):  
Aboulghasem Kazemi Korrani ◽  
Gary R. Jerauld ◽  
Kamy Sepehrnoori
Keyword(s):  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Mechanistic Modeling ◽  
Water Soluble ◽  
Exchange Reactions ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Simulator

Summary Low-salinity waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher-salinity waterflooding. Although there are many low-salinity experimental results reported in the literature, publications on modeling this process are rare. Although there remains some debate regarding the mechanisms of low salinity waterflooding process (LoSal EOR®)*, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Because no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc (Charlton and Parkhurst 2011), developed by the US Geological Survey, with UTCOMP (Chang 1990), the compositional reservoir simulator developed by The University of Texas at Austin. A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components—e.g., carbon dioxide (CO2), methane (CH4), and acidic/basic components of the crude—on buffering the aqueous pH value and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constraints are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low-salinity waterflooding. Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation on the basis of total ionic strength and multicomponent ion exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc, and the integrated tool is then used to match and interpret a low-salinity experiment published by Kozaki (2012) and the field trial performed by BP at the Endicott field.

scholarly journals Bulk and Surface Aqueous Speciation of Calcite: Implications for Low-Salinity Waterflooding of Carbonate Reservoirs

SPE Journal ◽  
2017 ◽  
Vol 23 (01) ◽  
pp. 84-101 ◽  
Author(s):  
Maxim P. Yutkin ◽  
Himanshu Mishra ◽  
Tadeusz W. Patzek ◽  
John Lee ◽  
Clayton J. Radke
Keyword(s):  
Ionic Strength ◽  
Ion Exchange ◽  
Crude Oil ◽  
Surface Charge ◽  
Double Layer ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Diffuse Double Layer ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Summary Low-salinity waterflooding (LSW) is ineffective when reservoir rock is strongly water-wet or when crude oil is not asphaltenic. Success of LSW relies heavily on the ability of injected brine to alter surface chemistry of reservoir crude-oil brine/rock (COBR) interfaces. Implementation of LSW in carbonate reservoirs is especially challenging because of high reservoir-brine salinity and, more importantly, because of high reactivity of the rock minerals. Both features complicate understanding of the COBR surface chemistries pertinent to successful LSW. Here, we tackle the complex physicochemical processes in chemically active carbonates flooded with diluted brine that is saturated with atmospheric carbon dioxide (CO2) and possibly supplemented with additional ionic species, such as sulfates or phosphates. When waterflooding carbonate reservoirs, rock equilibrates with the injected brine over short distances. Injected-brine ion speciation is shifted substantially in the presence of reactive carbonate rock. Our new calculations demonstrate that rock-equilibrated aqueous pH is slightly alkaline quite independent of injected-brine pH. We establish, for the first time, that CO2 content of a carbonate reservoir, originating from CO2-rich crude oil and gas, plays a dominant role in setting aqueous pH and rock-surface speciation. A simple ion-complexing model predicts the calcite-surface charge as a function of composition of reservoir brine. The surface charge of calcite may be positive or negative, depending on speciation of reservoir brine in contact with the calcite. There is no single point of zero charge; all dissolved aqueous species are charge determining. Rock-equilibrated aqueous composition controls the calcite-surface ion-exchange behavior, not the injected-brine composition. At high ionic strength, the electrical double layer collapses and is no longer diffuse. All surface charges are located directly in the inner and outer Helmholtz planes. Our evaluation of calcite bulk and surface equilibria draws several important inferences about the proposed LSW oil-recovery mechanisms. Diffuse double-layer expansion (DLE) is impossible for brine ionic strength greater than 0.1 molar. Because of rapid rock/brine equilibration, the dissolution mechanism for releasing adhered oil is eliminated. Also, fines mobilization and concomitant oil release cannot occur because there are few loose fines and clays in a majority of carbonates. LSW cannot be a low-interfacial-tension alkaline flood because carbonate dissolution exhausts all injected base near the wellbore and lowers pH to that set by the rock and by formation CO2. In spite of diffuse double-layer collapse in carbonate reservoirs, surface ion-exchange oil release remains feasible, but unproved.

scholarly journals Enhanced oil recovery efficiency of low-salinity water flooding in oil reservoirs including Fe2+ ions

2018 ◽  
Vol 37 (1) ◽  
pp. 355-374 ◽  
Author(s):  
Yeonkyeong Lee ◽  
Hyemin Park ◽  
Jeonghwan Lee ◽  
Wonmo Sung
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Water Flooding ◽  
Sulfate Ion ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Low Salinity Waterflooding ◽  
Injection Water ◽  
Salinity Water ◽  
Reservoir Simulator

The low-salinity waterflooding is an attractive eco-friendly producing method, recently, for carbonate reservoirs. When ferrous ion is present in the formation water, that is, acidic water, the injection of low-salinity water generally with neutral pH can yield precipitation or dissolution of Fe-minerals by pH mixing effect. FeSO4 and pyrite can be precipitated and re-dissolved, or vice versa, while siderite and Fe(OH)2 are insoluble which are precipitated, causing permeability reduction. Particularly, pyrite chemically reacts with low-salinity water and release sulfate ion, altering the wettability, favorably, to water-wet. In this aspect, we analyzed oil production focusing on dissolution of Fe-minerals and Fe-precipitation using a commercial compositional reservoir simulator. From the simulation results, the quantities of precipitation and dissolution were enormously large regardless of the type of Fe-minerals and there was almost no difference in terms of total volume in this system. However, among Fe-minerals, Fe(OH)2 precipitation and pyrite dissolution were noticeably large compared to troilite, FeSO4, and siderite. Therefore, it is essential to analyze precipitation or dissolution for each Fe-mineral, individually. Meanwhile, in dissolving process of pyrite, sulfate ions were released differently depending on the content of pyrite. Here, the magnitude of the generated sulfate ion was limited at certain level of pyrite content. Thus, it is necessary to pay attention for determining the concentration of sulfate ion in designing the composition of injection water. Ultimately, in the investigation of the efficiency of oil production, it was found that the oil production was enhanced due to an additional sulfate ion generated from FeS2 dissolution.

scholarly journals Chemical Compositions in Modified Salinity Waterflooding of Carbonate Reservoirs -- Experiment

2021 ◽  
Author(s):  
Maxim Yutkin ◽  
Clayton J. Radke ◽  
Tadeusz Patzek
Keyword(s):  
Calcium Carbonate ◽  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Single Phase ◽  
Theoretical Framework ◽  
Mineral Dissolution ◽  
High Dispersion ◽  
Carbonate Dissolution

<br>Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil<br>production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some adhered crude oil.<br>Composition design of the modified brine to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone,<br>which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity<br>hinders rational design of the tailored brine to improve oil recovery. <br>Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion<br>exchange, and dispersion (Yutkin et. al 2021). Here we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium<br>carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at<br>injection rates higher than 1000 ft/day. Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long<br>concentration history tails. <br>Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in<br>high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.<br><br>

A Mechanistic Integrated Geochemical and Chemical-Flooding Tool for Alkaline/Surfactant/Polymer Floods

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 32-54 ◽  
Author(s):  
Aboulghasem Kazemi Korrani ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
The United States ◽  
Mineral Dissolution ◽  
Mechanistic Modeling ◽  
United States Geological Survey ◽  
Chemical Flooding ◽  
Exchange Reactions ◽  
Asp Flooding ◽  
Alkaline Surfactant Polymer

Summary Mechanistic simulation of alkaline/surfactant/polymer (ASP) flooding considers chemical reactions between the alkali and the oil to form in-situ soap and reactions between the alkali and the minerals and brine. A comprehensive mechanistic modeling of such process remains a challenge, mainly caused by the complicated ASP phase behavior and the complexity of geochemical reactions that occur in the reservoir. Because of the lack of the microemulsion phase and/or lack of reactions that may lead to the consumption of alkali and resulting lag in the pH, a simplified ASP phase behavior is often used. A state-of-the-art geochemical package, IPhreeqc, of the United States Geological Survey was coupled with UTCHEM, an in-house research chemical-flooding reservoir simulator developed at The University of Texas at Austin (UT), for a robust, flexible, and accurate integrated tool to mechanistically model ASP floods. UTCHEM has a comprehensive three-phase (water, oil, microemulsion) flash package for the mixture of surfactant and soap as a function of salinity, temperature, and cosolvent concentration. Through this integrated tool, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, surface complexation, and ion exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium and kinetic conditions. Italic words are defined in Appendix A. IPhreeqc has rich databases of chemical species and also the flexibility to include the alkaline reactions required for modeling ASP floods. Hence, to the best of our knowledge, for the first time, the important aspects of ASP flooding are considered. An algorithm is presented for modeling the geochemistry in an implicit-in-pressure-and-explicit-in-concentration solution algorithm. Finally, we show how to apply the integrated tool, UTCHEM-IPhreeqc, to match three different reaction-related chemical-flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a nonacidic crude oil, and alkaline/cosolvent/polymer flooding.

Effects of asphaltenes and organic acids on crude oil-brine interfacial visco-elasticity and oil recovery in low-salinity waterflooding

Fuel ◽  
2016 ◽  
Vol 185 ◽  
pp. 151-163 ◽  
Author(s):  
Griselda Garcia-Olvera ◽  
Teresa M. Reilly ◽  
Teresa E. Lehmann ◽  
Vladimir Alvarado
Keyword(s):  
Organic Acids ◽  
Crude Oil ◽  
Oil Recovery ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Elevated-Temperature Caustic/Sandstone Interaction: Implications for Improving Oil Recovery (includes associated papers 11348 and 11548 )

1982 ◽  
Vol 22 (04) ◽  
pp. 453-462 ◽  
Author(s):  
Robert D. Sydansk
Keyword(s):  
Elevated Temperature ◽  
Low Temperature ◽  
Crude Oil ◽  
Sodium Hydroxide ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Water Soluble ◽  
Silicate Minerals ◽  
In Situ Formation

Abstract Caustic in the form of sodium hydroxide solutions is shown to interact strongly with sandstone at elevated temperature ( 185 deg. F). Such interaction has substantial influence on the success of secondary and tertiary oil-recovery sodium hydroxide floods carried out in sandstone formations of more ordinary temperatures. Caustic in the form of sodium hydroxide interacts with sandstone at elevated temperature to promotesignificant dissolution of the more susceptible silicate minerals, predominantly clay and large-surface-area silicaminerals,sandstone weight loss;increased porosity;propagation of significant concentrations of water-soluble silicates, including sodium orthosilicate;in-situ formation of new immobile aluminosilicate material;changes in permeability: andhydroxideion consumption. Caustic/sandstone interaction resulting from sodiumhydroxide dissolution of silicate minerals is limited by kinetics. The interaction increases with increasing temperature, increasing sodium hydroxide concentration, and increasing caustic/sandstone contact time. Therate and the amount of interaction are sensitive to sandstone mineralogy and lithology. Although not studied during this work, the presence of crude oil, along with crude-oil type, may affect the rate and the amount of- interaction. Based on the laboratory study of elevated temperature caustic/sandstone interaction involving silicate-mineral dissolution by sodium hydroxide, it is concluded that, atlower temperatures, the much slower dissolution interaction has implications for field application of sodiumhydroxide for improving waterflood sweep efficiency and enhancing oil recover. Specifically, during field applications, the slow interaction could deplete the active hydroxide ions. More common low-temperature field applications are especially susceptible because oflong caustic/sandstone contact times and because, ingeneral, relatively small concentrations of sodiumhydroxide have been used historically. This study points out that proper extrapolation of laboratory caustic flooding results to field conditions should account for slow kinetic phenomena. The study also helps explaindetrimental caustic/sandstone interactions and lowerthan-expected oil recoveries experienced during a number of long-duration low-temperature enhanced oil recovery (EOR) field tests and floods. On the positive side, the dissolution interaction, especially at elevated temperatures, generates in-situ significant concentrations of water-soluble silicates, including sodium or thosilicate. Water-soluble silicates have been reported as candidates for improving oil recovery and for use in pre flushes to condition formations for other EOR techniques. Other than noting their in-situ formation and propagation, we did not study the alkaline water-soluble silicates in detail, and they are not discussed. Introduction Caustic (alkaline) flooding is one of several chemical processes for EOR being studied by the petroleum industry. Caustic flooding has been reviewed by Johnson and more recently by Mayer et al and Castor. Historically, caustic-induced EOR generally has been considered to result from liquid/liquid(caustic/crude)interactions. An exception to the liquid/liquid interaction generalization is caustic EOR postulated to result under certain conditions from wetting changes. In general, wetting changes involve very minor liquid/rock interactions limited in principle to the pore walls of formation material. Field results in sandstone formations for caustic EOR to date have not been overly encouraging. Liquid/rock(caustic/sandstone) interactions often appear to contribute negatively. Caustic is consumed by sandstone both reversibly and irreversibly. Reversible consumption leads to caustic propagation at a slower rate than the aqueous flood front. SPEJ P. 453^

scholarly journals Chemical Compositions in Modified Salinity Waterflooding of Calcium Carbonate Reservoirs: Experiment

2022 ◽  
Author(s):  
M. P. Yutkin ◽  
C. J. Radke ◽  
T. W. Patzek
Keyword(s):  
Calcium Carbonate ◽  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Single Phase ◽  
Mineral Dissolution ◽  
High Dispersion ◽  
Carbonate Dissolution ◽  
Calcium Carbonate Dissolution

AbstractModified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some of adhered crude oil. Composition design of brine modified to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone, which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity hinders rational design of brines tailored to improve oil recovery. Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion exchange, and dispersion (Yutkin et al. in SPE J 23(01):084–101, 2018. 10.2118/182829-PA). Here, we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at injection rates higher than 3.5 $$\times$$ × 10$$^{-3}$$ - 3  m s$$^{-1}$$ - 1 (1000 ft/day). Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long concentration history tails. Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.

scholarly journals Chemical Compositions in Modified Salinity Waterflooding of Carbonate Reservoirs -- Experiment

2021 ◽  
Author(s):  
Maxim Yutkin ◽  
Clayton J. Radke ◽  
Tadeusz Patzek
Keyword(s):  
Calcium Carbonate ◽  
Ion Exchange ◽  
Crude Oil ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Single Phase ◽  
Theoretical Framework ◽  
Mineral Dissolution ◽  
High Dispersion ◽  
Carbonate Dissolution

<br>Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil<br>production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some adhered crude oil.<br>Composition design of the modified brine to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone,<br>which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity<br>hinders rational design of the tailored brine to improve oil recovery. <br>Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion<br>exchange, and dispersion (Yutkin et. al 2021). Here we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium<br>carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at<br>injection rates higher than 1000 ft/day. Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long<br>concentration history tails. <br>Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in<br>high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.<br><br>

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

A Numerical Investigation of Low Salinity Polymer Flooding Effects from a Geochemical Perspective

2021 ◽  
Author(s):  
Omar Chaabi ◽  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Aqueous Phase ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Solution Chemistry ◽  
Related Effect ◽  
Exchange Reactions ◽  
Two Phase ◽  
Low Salinity ◽  
Geochemical Reactions

Abstract Low salinity polymer (LSP) flooding is getting more attention due to its potential of enhancing both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MRST was coupled with the geochemical software IPhreeqc. The effects of polymer were captured by considering Todd-Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to PHREEQC database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST-IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against PHREEQC for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

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