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

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

10.26434/chemrxiv.14459319.v1 ◽

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

Modified 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 adhered crude oil. Composition design of the modified brine 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 the tailored brine 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 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 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 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.

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

10.26434/chemrxiv.14459319 ◽

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

Modified 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 adhered crude oil. Composition design of the modified brine 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 the tailored brine 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 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 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 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.

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

SPE Reservoir Evaluation & Engineering ◽

10.2118/169115-pa ◽

2016 ◽

Vol 19 (01) ◽

pp. 142-162 ◽

Cited By ~ 19

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.

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