Oil chemistry and its impact on heavy oil solution gas drive

Peng, Jing; Tang, Guiqian; Kovscek, Anthony R.

doi:10.1016/j.petrol.2009.01.005

Cited by 44 publications

(30 citation statements)

References 20 publications

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“…With a reported activation energy of 23.5 kJ/mol (Palandri and Kharaka 2004), k rxn weakly increases with temperature by a factor of four between 25 and 75 C. However, the presence of impurity metals and adsorptive organic materials significantly reduces k rxn , possibly by factors of 100 (Salem et al 1994;Eisenlohr et al 1999;Arvidson et al 2003). Because the asphaltenic component of crude oils typically contains both heavy metals and associated organic acids and bases (Peng et al 2009;Sjöblom et al 2015), we adopt a range of values for k rxn between 10 À5 and 10 À3 cm/s. Mineral dissolution occurs on exposed surface area.…”

Section: ðA-1þmentioning

confidence: 99%

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

et al. 2017

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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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Section: ðA-1þmentioning

confidence: 99%

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

et al. 2017

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“…Such phenomenon occurs when the solution gas is released from oil to form small dispersed, trapped gas bubbles inside the oil which flow with the oil because of the high viscosity of heavy oil. As a result, the oil is expanded and its viscosity is reduced due to gas bubbles (Yu and Shen 2008;Peng et al 2009;Wang et al 2009;Torabi et al 2012). However, when the reservoir pressure is below the pseudo-bubble point pressure, the gasoil ratio of the reservoir increases quickly, and the oil production rate decreases sharply because the gas bubbles trapped in the oil begin to coalesce together to form free gas phase (Liu et al 2011;Sun et al 2013).…”

Section: Introductionmentioning

confidence: 99%

Diffusion coefficients of natural gas in foamy oil systems under high pressures

et al. 2015

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The diffusion coefficient of natural gas in foamy oil is one of the key parameters to evaluate the feasibility of gas injection for enhanced oil recovery in foamy oil reservoirs. In this paper, a PVT cell was used to measure diffusion coefficients of natural gas in Venezuela foamy oil at high pressures, and a new method for determining the diffusion coefficient in the foamy oil was developed on the basis of experimental data. The effects of pressure and the types of the liquid phase on the diffusion coefficient of the natural gas were discussed. The results indicate that the diffusion coefficients of natural gas in foamy oil, saturated oil, and dead oil increase linearly with increasing pressure. The diffusion coefficient of natural gas in the foamy oil at 20 MPa was 2.93 times larger than that at 8.65 MPa. The diffusion coefficient of the natural gas in dead oil was 3.02 and 4.02 times than that of the natural gas in saturated oil and foamy oil when the pressure was 20 MPa. However, the gas content of foamy oil was 16.9 times higher than that of dead oil when the dissolution time and pressure were 20 MPa and 35.22 h, respectively.

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“…Peng et al 41 investigated the role of oil composition on heavy oil solution gas drive. It was found that oil composition plays a role in determining metastability of dispersed gas bubbles in foamy oil by core-level depletion and significant asphaltene content as well as substantial acid number and base number are indicators of whether oil is foamy.…”

Section: Effect Of Oil Compositionmentioning

confidence: 99%

Gas Recharging Process Study in Heavy Oil Reservoirs

Zhang

2014

Day 3 Thu, June 12, 2014

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Gas recharging process, as a supplemental technique for heavy oil reservoirs with thin layers, has attracted researchers' attention. This thesis focused on three post-cold production process studies-CH 4 recharging and depletion, CO 2 and C 3 H 8 huff-puff, and C 3 H 8 flooding. Two 18m in length glass beads and sand packed cores and one 1.5m in length sand packed core were used for testing. The mechanisms of each process were investigated. Foamy oil flow under the solution gas drive mechanism was clearly observed during two long core methane depletion processes.The effects of core length and permeability on oil recovery were discussed. CT scanning technique was applied to capture core saturation variations after each process at the 1.5m core, which helped better understanding of the mechanisms of the three gas recharging processes and also was successfully applied to explain what happened in two long cores.iii Acknowledgements

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Oil chemistry and its impact on heavy oil solution gas drive

Cited by 44 publications

References 20 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

Diffusion coefficients of natural gas in foamy oil systems under high pressures

Gas Recharging Process Study in Heavy Oil Reservoirs

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