Modelling Low-Salinity Water Flooding as a Tertiary Oil Recovery Technique

Olabode, Oluwasanmi; Alaigba, David; Oramabo, Daniel; Bamigboye, Oreofeoluwa

doi:10.1155/2020/6485826

Cited by 7 publications

(5 citation statements)

References 16 publications

(16 reference statements)

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“…Furthermore, this model adds a separate salt phase to the existing phase and solves a mass conservation equation for each block in the reservoir model. More detailed information on LSWI modeling by the Eclipse program at various water concentrations is presented in previous works (Knut 2012;Xie et al 2015;Qiao et al 2016;Olabode et al 2020;Al-Ibadi et al 2021). In this work, in the used model, the minimum distance from the ground to the first layer of the reservoir was 2500 m, and in the deepest part of the reservoir was 3100 m. The reservoir model included nine producers and two injection wells completed at the top of the reservoir.…”

Section: Simulation Of Recovery Factor At Various Salt Concentrations...mentioning

confidence: 99%

Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles

Khormali

Koochi

Varfolomeev

et al. 2022

J Petrol Explor Prod Technol

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In this work, the process of low salinity water injection (LSWI) into reservoirs at various salt concentrations was simulated in order to study the change in the oil recovery factor during oil production. The simulation results of the recovery factor were compared with the experimental data. The results demonstrated that the simulation data were in good agreement with the experimental results. In addition, the formation damage (rock permeability reduction) in carbonate core samples was evaluated through coreflood experiments during LSWI in the range of salt concentration and temperature of 1500–4000 ppm and 25–100 °C, respectively. In the worst scenario of LSWI, the rock permeability has reached about 83% of the initial value. Our previous correlation was used to predict the formation damage in LSWI. In this case, the R-squared value between predicted and experimental data of rock permeability ratios was more than 0.97. Furthermore, the recovery factor during LSWI was analyzed with and without the use of DTPMP scale inhibitor (diethylenetriamine penta (methylene phosphonic acid)), and various nanoparticles (TiO2, SiO2, Al2O3). The results of the coreflood experiments showed that the use of scale inhibitor provides an increase in the recovery factor by more than 8%. In addition, the highest recovery factor was observed in the presence of SiO2 nanoparticles at 0.05 wt.%. The oil displacement during LSWI in the porous media with SiO2 particles was better than TiO2 and Al2O3. The recovery factor in the presence of SiO2, TiO2, and Al2O3 with DTPMP was 72.2, 62.4, and 59.8%, respectively. Among the studied nanoparticles, the lowest values of the oil viscosity and interfacial tension (IFT) between oil and water were observed when using SiO2. Moreover, the contact angle was increased by increasing the brine concentration. The contact angle with the use of SiO2, TiO2, and Al2O3 at 0.05 wt.% was reduced by 11.2, 10.6, and 9.9%, respectively.

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Section: Simulation Of Recovery Factor At Various Salt Concentrations...mentioning

confidence: 99%

Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles

Khormali

Koochi

Varfolomeev

et al. 2022

J Petrol Explor Prod Technol

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“…LSWF is a secondary and tertiary oil production technique that involves injecting diluted formation water, seawater, or smart water to enhance the oil recovery process. , Despite its cost-effectiveness, environmental benefits, and potential for up to 15% additional oil recovery, LSWF has not gained widespread operational acceptance and remains largely confined to experimental applications . The main challenge lies in upscaling the results of LSWF mechanisms studied across various reservoir scales to generate standardized operational parameters, reduce associated reservoir damage risks, and facilitate broader LSWF field implementation. ,− The commercialization and maturity of LSWF have been hindered by these challenges, but extensive microscale studies have revealed that wettability alteration plays a crucial role in LSWF interactions. As a result, modeling wettability alteration has become the primary focus when simulating LSWF in both core and large-scale models across different platforms. − …”

Section: Introductionmentioning

confidence: 99%

“… 9 The main challenge lies in upscaling the results of LSWF mechanisms studied across various reservoir scales to generate standardized operational parameters, reduce associated reservoir damage risks, and facilitate broader LSWF field implementation. 4 , 10 − 12 The commercialization and maturity of LSWF have been hindered by these challenges, but extensive microscale studies have revealed that wettability alteration plays a crucial role in LSWF interactions. As a result, modeling wettability alteration has become the primary focus when simulating LSWF in both core and large-scale models across different platforms.…”

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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“…The presence of salt causes an electrostatic repulsion of polymer chains, which leads to its contraction and the eventual loss of viscosity [14]. Simulation studies on low-salinity-water flooding have been considered by [15] to reduce the reservoir saline contents for light oil reservoirs with additional recoveries of 11% over water flooding, but the challenge with this option is low performance in medium to heavy oil reservoirs [16]. References [17][18][19] have experimentally investigated the oil recovery performances of polymer flooding options with a preconditioned reservoir with low salinity.…”

Section: Introductionmentioning

confidence: 99%

Effect of Salt Concentration on Oil Recovery during Polymer Flooding: Simulation Studies on Xanthan Gum and Gum Arabic

Olabode,

Akinsanya,

Daramola

et al. 2023

Polymers

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Oil recoveries from medium and heavy oil reservoirs under natural recovery production are small because of the high viscosity of the oil. Normal water flooding procedures are usually ineffective, as the injected water bypasses much of the oil because of its high mobility. Thermal flooding processes are desirable but have many disadvantages from costs, effects on the environment, and loss of lighter hydrocarbons. Chemical flooding options, such as bio-polymer flooding options, are attractive, as they are environmentally friendly and relatively cheap to deploy and help to increase the viscosity of the injecting fluid, thereby reducing its mobility and increasing its oil recovery. The downside to polymer flooding includes reservoir temperature, salinity, molecular weight, and composition. Six weight percentages of two polymers (xanthan gum, XG, and gum arabic, GA) are dissolved in water, and their viscosity is measured in the laboratory. These viscosities are incorporated with correlations in the Eclipse software to create models with different polymer concentrations of (0.1% wt., 0.2% wt., 0.3% wt., 0.4% wt., 0.5% wt., and 1% wt.). A base case of natural recovery and water injection was simulated to produce an oil recovery of 5.9% and 30.8%, respectively, while at 0.1% wt. and 1% wt., respectively, oil recoveries of 38.8% and 45.7% (for GA) and 48.1% and 49.8% (for XG) are estimated. At 5% and 10% saline conditions, a drop in oil recovery of (4.6% and 5.3%) is estimated during GA flooding and (1.2% and 1.7%) for XG flooding at 1% wt., respectively. XG exhibits higher oil recoveries compared to GA at the same % wt., while oil recoveries during GA floodings are more negatively affected by higher saline concentrations.

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Modelling Low-Salinity Water Flooding as a Tertiary Oil Recovery Technique

Cited by 7 publications

References 16 publications

Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles

Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles

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

Effect of Salt Concentration on Oil Recovery during Polymer Flooding: Simulation Studies on Xanthan Gum and Gum Arabic

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