Surface Complexation Modeling for Low Salinity Polymer (LSP) Injection in Carbonate Reservoirs Under Harsh Conditions

Hassan, Anas M.; Al-Shalabi, Emad W.; Adila, Ahmed S.; Fathy, Ahmed; Kamal, Muhammad S.; Patil, Shirish; Hussain, Syed M. Shakil

doi:10.2118/216501-ms

Cited by 3 publications

(1 citation statement)

References 41 publications

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“…Using CMG-STARS and PHREEQC, they interpolated modified relative permeabilities from the measured (or simulated) maximum energy barrier in the polymer–brine–rock interfaces, thereby upscaling and analyzing wettability alteration occurring during LSWF, while on the MRST platform, Al-Shalabi et al coupled MRST with PHREEQC to model the geochemical role of LSP flooding, considering the sensitivity of the polymer (HPMA) and its impact on breakdown and lower displacement recovery factor in high-salinity conditions. Moreover, on MRST-PHREEQC, Hassan et al − also modeled the polymer–brine–rock (PBR) system interaction and its impact on LSP performance as influenced by reservoir parameters such as salinity/hardness, polymer hydrolysis, rock composition/permeability, and temperature. These studies focused on the resultant polymer rheological impact (adsorption and viscosity effects).…”

Section: Introductionmentioning

confidence: 99%

Macroscale Modeling of Geochemistry Influence on Polymer and Low-Salinity Waterflooding in Carbonate Oil Reservoirs

Limaluka,

Elakneswaran,

Hiroyoshi

2024

ACS Omega

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The enhancement of oil recovery (EOR) through low-salinity waterflooding (LSWF) and the emerging hybrid with a polymer (LSP) has proven to be effective at microscale investigations and cost-effective with ease of operation at field-scale tests. Their application in carbonate oil reservoirs, which typically occur oil-wet, presents a particularly essential capacity given that over half of the global oil reserves are hosted in carbonate formation. However, modeling the mechanisms involved to predict and evaluate the performance of low salinity-based EOR at a large scale is complex and requires the integration of geochemistry in reservoir simulation to upscale the interfacial interactions of crude oil, brine, and rock observed at the micrometer scale. This study presents an integrated approach that combines MRST’s polymer model with PHREEQC geochemical modeling to simulate LSWF at the reservoir scale. Using single-phase and multiphase experimental flooding data for validation, the coupled model was shown to accurately predict effluent ionic and oil recovery profiles. The simulation of LSWF and LSP both exhibited additional tertiary oil recovery, with LSWF and LSP showing 3 and 2%, respectively, which are consistent with previously reported field and core flooding results. Furthermore, the sequential application of formation water (FW), LSWF, and LSP flooding in secondary mode showed a high increase in oil recovery, with oil recovery percentages of 61, 20, and 19%, respectively. However, the FW results were 50% lower compared to regular core flooding due to upscaling limitations. The modeling of vertical and anisotropic permeability heterogeneity effects showed a positive synergy with low-salinity floodings, resulting in a 4% drop and 3 and 1% increase in FW, LSWF, and LSP, respectively. These findings demonstrate the potential of the coupled MRST-PHREEQC model in accurately simulating hydrogeochemical interactions during LSWF/LSP at the reservoir scale, providing valuable insights for the optimization of low salinity-based EOR strategies in carbonate reservoirs.

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Section: Introductionmentioning

confidence: 99%

Macroscale Modeling of Geochemistry Influence on Polymer and Low-Salinity Waterflooding in Carbonate Oil Reservoirs

Limaluka,

Elakneswaran,

Hiroyoshi

2024

ACS Omega

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Modeling of Low Salinity Polymer (LSP) Interactions in Carbonates from Geochemical and Surface Chemistry Perspectives

Hassan,

Adila,

Al-Shalabi

et al. 2024

Day 2 Tue, February 13, 2024

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Low Salinity Polymer (LSP) injection is a hybrid synergistic enhanced oil recovery (EOR) technique that improves displacement and sweep efficiencies by combining the advantages of both low salinity and polymer flooding methods. Nevertheless, proper design of LSP flooding at field-scale requires a predictive mechanistic model that captures polymer-brine-rock (PBR) interactions. Therefore, this study investigates the impact of water chemistry on polymer behavior in porous media in order to gain a better understanding of the PBR-system. In particular, we examine the effect of salinity and hardness on polymer viscosity and adsorption in dolomite formations during LSP flooding employing our in-house coupled MRST-IPhreeqc simulator. Furthermore, to capture the geochemistry of the LSP process, the MRST-IPhreeqc simulator incorporates surface complexation reactions as well as aqueous, mineral dissolution and/or precipitation reactions. The findings of this study suggest that the 5-times spiked salinity and hardness scenarios are more favorable than those of 10-times spiked salinity and hardness, which were supported by their respective polymer viscosity losses of 75% and 82% for salinity spiking, and 58% and 63% for hardness spiking. Also, the effects of 10-times spiked Ca2+, 10-times spiked Mg2+, and 2-times spiked SO42-on polymer viscosity were studied with estimated viscosity losses of 61%, 61%, and 46%, respectively. The latter signifies the importance of sulfate spiking for reducing polymer viscosity loss while avoiding exceeding sulfate limit for scale formation and reservoir souring. For the effect of salinity on polymer adsorption, it was observed that the increase in salinity from the base case scenario (623 ppm) to 5- and 10-times spiked salinity, results in an increase in the dynamic polymer adsorption from 53 μg/g-rock to 59 and 68 μg/g-rock, respectively. Additionally, comparing the 10-times spiked Mg2+, 10-times spiked Ca2+, and the 2-times spiked SO42- scenarios, the 10-times spiked Mg2+ case resulted in the maximum polymer adsorption (87 μg/g-rock). This is due to the surface complexation reactions of magnesium surface species at dolomite rock surface with polymer molecules forming Mg-polymer surface complexes. In contrast, the calcium and sulfate do not form surface complexes through reactions with the polymer. This indicated that the divalent cation's design might impact the viscosity of the LSP solution, and therefore, it is crucial to carefully consider it when optimizing the LSP process in carbonates. Thus, proper design of LSP flooding at field-scale requires a predictive mechanistic model that captures PBR interactions which is covered in this work.

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Research on water-out mode and differential perforation in thick carbonate reservoir

Junshuai,

Peiyuan,

Jian

et al. 2024

Front. Energy Res.

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The development of anti-rhythmic carbonate reservoirs in the Middle East often encounters challenges such as water hold-up and reverse coning during the water injection process, leading to premature water breakthrough and various water-out issues. The unclear understanding of these phenomena, attributed to strong reservoir heterogeneity, results in a relatively low recovery degree in water injection development. This paper investigates the mechanisms behind water hold-up and reverse coning phenomena, offering detailed solutions. Numerical models of the oil reservoirs were developed, and an extensive study of influencing factors, including reservoir types, Kv/Kh, water injection pressure differential, wettability, and perforation position, was conducted to unveil the underlying mechanisms. Key findings indicate that the water hold-up phenomenon is influenced by capillary force barriers due to wettability and high-perm streaks, while the reverse coning phenomenon depends on the combined forces of gravity, capillary force and downward production differential among which downward production differential is the dominant factor compared to capillary force and gravity. The study also proposes a differential perforation principle tailored to different water-out types to enhance vertical sweep efficiency. The differential perforation principle is as follows: the optimal perforation position is at top layer and the optimal perforation length approximately accounts for 1/4 of the total oil layer thickness for water-out in bottom; the avoidance perforation height in top accounts for 1/6 of the total oil layer thickness and the optimal perforation length approximately accounts for 1/2 of the total oil layer thickness for water-out in top; the avoidance perforation height in top and bottom accounts for 1/5 and 2/5 of the total oil layer thickness respectively for water-out in both top and bottom.

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Surface Complexation Modeling for Low Salinity Polymer (LSP) Injection in Carbonate Reservoirs Under Harsh Conditions

Cited by 3 publications

References 41 publications

Macroscale Modeling of Geochemistry Influence on Polymer and Low-Salinity Waterflooding in Carbonate Oil Reservoirs

Macroscale Modeling of Geochemistry Influence on Polymer and Low-Salinity Waterflooding in Carbonate Oil Reservoirs

Modeling of Low Salinity Polymer (LSP) Interactions in Carbonates from Geochemical and Surface Chemistry Perspectives

Research on water-out mode and differential perforation in thick carbonate reservoir

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