Novel Impressions of Hybrid Low Salinity Polymer (LSP) Injection: A Geochemical Modeling Study

Abstract

The hybrid Enhanced Oil Recovery (EOR) method of Low Salinity Polymer (LSP) injection is an advanced synergetic coalescence with remarkable additional oil recovery capability. Several studies have reported that the LSP process significantly enhances polymer rheology and viscoelasticity, along with improving the injectivity and displacement efficiency. However, to accurately simulate and capture the complex geochemistry of the Polymer-Brine-Rock (PBR) system during LSP-injection, sophisticated mechanistic predictive models are required, which the literature rarely discusses. Therefore, we modeled the PBR-system interactions in this study, using our coupled numerical simulator, in order to acquire new understandings of the LSP-injection process. Our coupled numerical simulator integrates the MATLAB-Reservoir-Simulation Toolbox (MRST) with the geochemical-software IPhreeqc. This study investigates the effects of variations in water chemistry (salinity and hardness), permeability, and polymer hydrolysis on polymer viscosity and adsorption through mechanistic modeling of the LSP process using the MRST-IPhreeqc coupled simulator. In this sensitivity analysis, the various injected water salinity and hardness models were generated by spiking and diluting both the salinity and the hardness of the baseline model by 3-, 5-, and 15-times each, and subsequently investigating their impact on polymer viscosity and adsorption. Furthermore, to evaluate the effect of various degrees of hydrolysis on polymer viscosity, we investigated the polymer hydrolysis degree of 30% (base-case), and then 15% and 80% polymer hydrolysis degrees. Next, the impact of different permeabilities on polymer adsorption was investigated for the base-case permeability (71 mD), low permeability (50 mD), and high permeability (150 mD) scenarios. A number of mineral dissolutions can occur in the PBR-system causing the calcium (Ca2+) and magnesium (Mg2+) ions to release, which then form polymer complexes to massively reduce the polymer-viscosity. Also, mechanical entrapment can lead to high polymer adsorption during LSP flooding. Based on the sensitivity analysis, the results of the investigation regarding the effect of salinity on polymer viscosity indicated that the scenario of 15-times spiked salinity (9345 ppm) is more beneficial than those of 5-times (3115 ppm) and 3-times (1869 ppm) spiked salinities, based on their corresponding polymer-viscosity losses of 8%, 10%, and 19%. The same effect was observed for the increase in hardness (Ca2+ + Mg2+) scenario where 15-times spiked hardness (165 ppm) is superior to the 5-times (55 ppm) and 3-times spiked (33 ppm) scenarios, based on their corresponding polymer-viscosity losses of 25%, 47%, and 52%. Similarly, examining the impact of polymer hydrolysis on polymer viscosity indicated that the viscosity of the polymer decreases as the degree of hydrolysis increases to 80% or decreases to 15%. Regarding the effect of salinity and hardness variations on polymer adsorption, the results showed that as the salinity and hardness increase, polymer adsorption increases too. Contrariwise, the diluted salinity and hardness solutions resulted in lower adsorption levels. In terms of the impact of permeability on polymer adsorption, mechanical entrapment causes the polymer adsorption to rise at a low permeability of 50 mD, and conversely, the adsorption starts to decline at high permeability of 150 mD. Finally, according to the CR calculations, if CR > 1, this implies low viscosity loss in the LSP-solution, which equates to the cation threshold concentration of 130 ppm. At CR < 0.5, the LSP-solution will likely have a significant decrease in viscosity. When 0.5 < CR < 1, additional assessment for risk of viscosity loss is needed. Therefore, the novel findings resulting from this study can help design more effective LSP-injection strategies at field-scale.

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

“…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).…”