Polymer flooding is one of the most successful chemical EOR (enhanced oil recovery) methods, and is primarily implemented to accelerate oil production by sweep improvement. However, additional benefits have extended the utility of polymer flooding. During the last decade, it has been evaluated for use in an increasing number of fields, both offshore and onshore. This is a consequence of (1) improved polymer properties, which extend their use to HTHS (high temperature high salinity) conditions and (2) increased understanding of flow mechanisms such as those for heavy oilmobilization. A key requirement for studying polymer performance is the control and prediction of in-situ porous medium rheology. The first part of this paper reviews recent developments in polymer flow in porous medium, with a focus on polymer in-situ rheology and injectivity. The second part of this paper reports polymer flow experiments conducted using the most widely applied polymer for EOR processes, HPAM (partially hydrolyzed polyacrylamide). The experiments addressed highrate, near-wellbore behavior (radial flow), reservoir rate steady-state flow (linear flow) and the differences observed in terms of flow conditions. In addition, the impact of oil on polymer rheology was investigated and compared to single-phase polymer flow in Bentheimer sandstone rock material. Results show that the presence of oil leads to a reduction in apparent viscosity.

This study includes solving non-Newtonian Navier–Stokes equation in three-dimensions (real rock images) and two-dimensions (simplified pore geometries) using the finite-difference method. The purpose of this study is to improve understanding of local phenomena leading to the mobilization of residual oil. This involves local pressure variations for non-Newtonian polymers and compares it with Newtonian fluid behavior. When a higher degree of shear thickening is induced, more flow diversion to side channels perpendicular to the main flow path and larger drag on fluids inside side channels will occur. This is consistent with oil mobilization and lowering of residual oil saturation.

Salt precipitation during geological CO2 storage (GCS) in saline aquifers can impair the injectivity of large-scale projects. Laboratory studies indicate that this process is sensitive to capillary force, but scaling-up to field conditions is complex due to radial flow, gravity, and geological heterogeneity. This study utilizes 3D simulations to characterize salt precipitation mechanisms in realistic storage formations. Non-dimensional groups, e.g., capillary number (Ca) and gravity number (Gr), are used to characterize the relative impact of capillary, viscous, and gravity forces on salt formation. Three distinct regimes emerge for homogeneous systems: 1) capillary-dominated regime for Ca < 1 with severe salt precipitation at the inlet; 2) viscous-dominated regime for Ca > 1 and Gr < 0.2 with low-to-moderate salt precipitation; and 3) gravity-dominated regime for Ca > 1 and Gr > 0.2 where gravity override leads to localization of salt deposits inside the reservoir. The Ca-Gr regimes generally hold for heterogeneous systems. Additional complexity includes increased salt precipitation in high-permeability zones due to lower Ca enhanced by capillary-induced imbibition of saline water from low-permeability zones. Tortuous flow paths can also emerge, further exacerbating pressure build-up. These novel characterizations can assist practitioners in designing mitigation strategies for injectivity impairment in large-scale operations.

Depleted hydrocarbon reservoirs are often considered as suitable candidates for geological CO2 storage due to their proven injectivity (e.g., permeability and thickness), known storage capacity (e.g., pore volume), and established containment characteristics (e.g., presence of geological cap rocks). In addition, they offer existing injection infrastructures and comprehensive information from the geological formations that will be targeted for the CO2 storage operation. However, the injection of CO2 at high pressure into such low-pressure reservoirs is affected by the well-known Joule-Thomson cooling effect. The expansion of high-pressure CO2 into a depleted reservoir results in a localized temperature reduction in the wellbore region. This significant cooling effect may induce thermal fractures within the reservoir and cap rock; it can freeze the irreducible water, lead to formation of hydrates, and result in salt precipitation. While induced fractures can benefit the well injectivity, they might pose a risk to the integrity of the wellbore and the containment of reservoir. Additionally, formation of hydrates due to temperature drop near well may lead to the wellbore blockage, permeability reduction, and ultimately, injectivity impairment. Therefore, understanding the Joule-Thomson effect and associated parameters that can affect the degree of cooling in the near-wellbore region is crucial prior to the design phase of any CO2 injection projects into depleted reservoirs.In this study, we employ the TOUGH2-ECO2M simulation tool to assess the significance of the Joule-Thomson cooling effect in underground CO2 storage. Initially, the simulation model was verified using a classic Joule-Thomson expansion experiment with pure CO2, yielding its coefficients with less than 3% difference against the available published references and experimental data. This provided confidence in our analysis to perform further investigation of complex interplay between injected CO2 and reservoir dynamics. Key parameters, including injection rate, bottomhole temperature, reservoir permeability, and initial reservoir pressure, were studied to understand how these factors would influence the strength of the Joule-Thomson cooling effect in depleted gas reservoirs.In practice, the bottomhole temperature depends on various parameters, including the injection rate, well depth, wellhead temperature, tubing properties, and the geothermal gradient. In the current simulation, the wellbore flow is not explicitly modelled, and therefore, it is treated as a variable parameter. The impact of permeability and injection rate is examined independently in a sensitivity analysis. Despite their analogous influence on pressure drop, as dictated by Darcy's law, it is essential to recognize that alterations in temperature can make changes in the viscosity of CO2, subsequently exerting an indirect influence on the pressure drop within the system and amount of cooling effect.Simulation results indicated that more pronounced cooling can be experienced due to higher injection rate, lower reservoir permeability, elevated bottomhole temperature, or lower reservoir pressure. Interestingly, the bottomhole temperature drop near the wellbore exhibited notable behaviour. It deviated significantly from the theoretically calculated values, which is due to the residual heat from the underground formations. Temperature drop occurred gradually over time, and it was extended beyond the immediate wellbore region, propagating deep into the reservoir.To further explore the impact of bottomhole temperature on the Joule-Thomson cooling effect, we assumed a base case scenario in which the injection bottomhole temperature was equal to the initial reservoir temperature of 75 °C and reservoir initial pressure was 50 bars. Simulation results indicated that a maximum observed temperature-drop of 28 °C was caused by the Joule-Thomson cooling effect. In another scenario, the bottomhole temperature (20 °C) was significantly lower than the initial reservoir temperature (75 °C). In this case, the observed temperature drop due to the Joule-Thomson effect was only 4 °C. A comparison of these scenarios suggests that when CO2 is injected at lower temperature than reservoir temperature, the Joule-Thomson cooling effect would likely not promote formation of hydrates.While Joule-Thomson cooling effect may present other challenges (e.g., induced fractures), based on the current simulation results it does not seem to pose significant concerns regarding hydrate formation in the context of underground CO2 storage. This study is of significant practical considerations for the design of effective CO2 injection strategies into depleted hydrocarbon reservoirs.