Wettability Alteration with Brine Composition in High Temperature Carbonate Rocks

Chandrasekhar, Sriram; Sharma, Himanshu; Mohanty, Kishore K.

doi:10.2118/181700-ms

Cited by 50 publications

(31 citation statements)

References 21 publications

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“…In a landmark contribution, Yousef et al (2011) detailed the viability of LSW with seawater in a Middle East carbonate. Later works experimentally confirm the earlier findings of successful oil recovery by LSW in carbonate rock (Zahid et al 2012;Chandrasekhar and Mohanty 2013;Alshakhs and Kovscek 2015).…”

supporting

confidence: 80%

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

Yutkin¹,

Mishra²,

Radke³

et al. 2016

SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition

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SummaryLow-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 (CO 2 ) 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 CO 2 content of a carbonate reservoir, originating from CO 2 -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 calcitesurface 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 CO 2 . In spite of diffuse double-layer collapse in carbonate reservoirs, surface ion-exchange oil release remains feasible, but unproved.Introduction LSW refers to improved oil recovery achieved by waterflooding a reservoir with brine of lower salinity than that of the field brine. The process is alluring because of simplicity, favorable economics, and large potential. In some applications, seawater is inj...

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supporting

confidence: 80%

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

Yutkin¹,

Mishra²,

Radke³

et al. 2016

SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition

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“…Several laboratory studies have been performed using low salinity water injection in carbonates (Hognesen et al, 2005;Webb et al, 2005;Zhang et al, 2007;Gupta et al, 2011;Yousef et al, 2011Yousef et al, , 2012aZhang and Sarma, 2012;Chandrasekhar and Mohanty, 2013). Most studies have confirmed a positive response to low salinity injection, which is translated into additional oil recovery in both secondary and tertiary injection modes.…”

Section: Low Salinity Water Injection (Lswi)mentioning

confidence: 99%

“…This work represents a synthetic coreflood case with a real reservoir fluid and rock properties similar to the properties in Chandrasekhar and Mohanty (2013). The corefloods were simulated at temperature of 248°F and a pressure of 4000 psi.…”

Section: Rock and Fluid Propertiesmentioning

confidence: 99%

Modeling the Combined Effect of Injecting Low Salinity Water and Carbon Dioxide on Oil Recovery from Carbonate Cores

2014

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This paper investigates the combined effect of injecting low salinity water (LSWI) and carbon dioxide (CO 2 ) on oil recovery from carbonate cores. The combined effect of LSWI and CO 2 injection on oil recovery was predicted by performing several 1D simulations using measured reservoir rock and fluid data. These simulations included the effect of salinity on both miscible and immiscible continuous gas injection (CGI), simultaneous water-alternating-gas (SWAG), constant water-alternating-gas (WAG), and tapered (WAG). For SWAG and constant and tapered WAG, both seawater and its dilutions were simulated. CO 2 was injected above its minimum miscibility pressure. Baker's three-phase relative permeability model was modified to account for the effect of salinity on the water/oil relative permeability.The results show that SWAG, whether using seawater or its dilutions, outperformed all other tertiary injection modes in terms of oil recovery. Moreover, the SWAG process has both the highest tertiary recovery factor (TRF) and the lowest utilization factor (UF). This study highlights the advantage of using low salinity water along with miscible CO 2 . The miscible CO 2 displaces the residual oil saturation whereas the low salinity water boosts the production rate by increasing the oil relative permeability through wettability alteration towards more a water-wet state. The latter finding was supported by comparing our simulations with the two corefloods reported by Chandrasekhar and Mohanty (2014). These corefloods were conducted in SWAG tertiary mode using seawater and its dilutions. Fractional flow analysis shows that SWAG with low salinity water requires less injected solvent compared to SWAG with seawater and miscible CGI.

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“…In carbonate rocks, several approaches have been tested and proven. A salinity range between 5000–50 000 ppm and a variation of active ions (Ca 2+ , Mg 2+ , and SO 4 2− ) and non‐active ions (Na + and Cl − ) have been successfully applied, and have been proven to yield recoveries in the range of 5–20 % original‐oil‐in‐place …”

Section: Introductionmentioning

confidence: 99%

“…A salinity range between 5000-50 000 ppm and a variation of active ions (Ca 2þ , Mg 2þ , and SO 4 2À ) and non-active ions (Na þ and Cl À ) have been successfully applied, and have been proven to yield recoveries in the range of 5-20 % original-oil-in-place. [5,[8][9][10][11] Several routes that could be responsible for this wettability alteration process have been reported, including surface charge alteration, multi-ion exchange, and mineral alteration in terms of precipitation/dissolution. [11][12][13] However, disparities do exist as to how these routes interplay among themselves, because only a very few experimental studies have reported the relationship between the histories of produced ions and the incremental amount of oil recovered.…”

Section: Introductionmentioning

confidence: 99%

An Analytical Solution to Interpret Active Ion Transport During Chemically‐Tuned Waterflooding Process in High‐Temperature Carbonate Rocks

Awolayo

Sarma

2018

Can J Chem Eng

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Recent studies on carbonate reservoirs suggest that modifying the injected brine chemistry leads to a competition amongst ions at the rock surface sites, causing alteration in the rock wettability. As such, the potential increase in oil recovery heavily relies on the relationship between the ion transport and chemical reaction. In this work, we highlighted the three processes that govern this relationship as advection by fluid transport, hydrodynamic dispersion resulting in spreading, and sorption of the ions to the rock. An analytical solution to the mathematical equations describing solute reactive transport was derived based on the advection‐reaction‐dispersion equation (ARDE). Our model was first used to replicate produced ion histories from single phase experiments to emphasize the impact of the active ions on rock surface sites. We then studied the movement of the active ions by predicting the breakthrough composition of different ions during oil‐brine displacement experiments and evaluated the impact of the transport and reaction parameters on the wettability change. The wettability change profile was captured in terms of the sorbed ion concentration, where a high retardation was observed for the active ions. The observed oil recoveries in a data set of two‐phase experiments were correlated to the resultant effect of the rock surface chemistry. This study highlights the importance of rock surface chemistry on wettability change and oil production from carbonate rocks.

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Wettability Alteration with Brine Composition in High Temperature Carbonate Rocks

Cited by 50 publications

References 21 publications

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

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

Modeling the Combined Effect of Injecting Low Salinity Water and Carbon Dioxide on Oil Recovery from Carbonate Cores

An Analytical Solution to Interpret Active Ion Transport During Chemically‐Tuned Waterflooding Process in High‐Temperature Carbonate Rocks

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