Summary Chemical enhanced oil recovery (EOR) leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high total acid number (TAN) could be produced by the injection of alkali. Alkali might lead to the generation of soaps and emulsify the oil. However, the generated emulsions are not always stable. Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. On the basis of the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in the formation of initial emulsions is observed. Micromodel experiments are performed to investigate the effects on the pore scale. For the injection of alkali into high-TAN oils, the mobilization of residual oil after waterflooding is seen. The oil mobilization results from the breaking up of oil ganglia or the movement of elongated ganglia through the porous medium. As the oil is depleting in surface-active components, residual oil saturation is left behind either as isolated ganglia or in the down gradient side of grains. Simultaneous injection of alkali and polymers leads to a higher incremental oil production in the micromodels owing to larger pressure drops over the oil ganglia and more-effective mobilization accordingly. Coreflood tests confirm the micromodel experiments, and additional data are derived from these tests. Alkali/cosolvent/polymer (ACP) injection leads to the highest incremental oil recovery of the chemical agents, which is difficult to differentiate in micromodel experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micromodels, the incremental oil recovery is also higher for alkali/polymer (AP) injection than with alkali injection only. To evaluate the incremental operating costs of the chemical agents, equivalent utility factors (EqUFs) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and, hence, the lowest chemical incremental operating expenditures are incurred by the injection of Na2CO3; however, the highest incremental recovery factor is seen with ACP injection. It should be noted that the incremental oil recovery owing to macroscopic-sweep-efficiency improvement by the polymer needs to be accounted for to assess the efficiency of the chemical agents.

Polymer flooding most commonly uses partially hydrolyzed polyacrylamides (HPAM) injected to increase the declining oil production from mature fields. Apart from the improved mobility ratio, also the viscoelasticity-associated flow effects yield additional oil recovery. Viscoelasticity is defined as the ability of particular polymer solutions to behave as a solid and liquid simultaneously if certain flow conditions, e.g., shear rates, are present. The viscoelasticity related flow phenomena as well as their recovery mechanisms are not fully understood and, hence, require additional and more advanced research. Whereas literature reasonably agreed on the presence of these viscoelastic flow effects in porous media, there is a significant lack and discord regarding the viscoelasticity effects in oil recovery. This work combines the information encountered in the literature, private reports and field applications. Self-gathered laboratory data is used in this work to support or refuse observations. An extensive review is generated by combining experimental observations and field applications with critical insights of the authors. The focus of the work is to understand and clarify the claims associated with polymer viscoelasticity in oil recovery by improvement of sweep efficiency, oil ganglia mobilization by flow instabilities, among others.

This work examines the potential use of two different nanoparticle solutions for EOR applications. Combining the evaluation of fluid-fluid interactions and spontaneous imbibition experiments, we present a systematic workflow. The goal of the study was to enable the generation of predictive scenarios regarding the application of Nano-EOR in OMV's assets. Therefore, influence of high and low TAN crude oil, core mineralogy, composition of the nanofluid on wettability alteration and recovery were studied. Nanomaterials used in this work employ inorganic nano-sized particles in a colloidal particle dispersion. We evaluated two types; one utilizes surface-modified silicon dioxide nanoparticles, while the other employs a synergistic blend of solvent, surfactants and surface-modified silicon-dioxide nanoparticles. IFT experiments were performed using a spinning-drop tensiometer and results were compared at ~180 min of observation. Amott-Harvey experiments enabled investigating wettability alteration considering effects of crude-oil composition and core mineralogy (~5 and ~10% clay content). Interfacial tension reduction was observed for both nanofluids. The blend yielded slightly lower values (~0.5- 0.6 mN/m) compared to the nanoparticles-only fluid (~0.8 mN/m), which is most likely related to the surfactant contained in the formulation. Amott-Harvey spontaneous imbibition experiments depicted clear wettability alterations for both nanofluids. Cores with ~5% clay content exhibited a water-wettish behavior, and additional recoveries using the nanofluids were up to 10%. In the cores containing ~10% clay, the nanoparticle-only fluid spontaneously imbibes to the rock matrix and quickly displaces large amounts of oil (~70% independently of the oil type that was used). Contrary, the blend yields higher recovery from the 10% clay cores, with the high TAN oil than with low TAN oil (57 ± 3 vs. 45 ± 1%). However, in 5% clay cores, faster imbibition was observed when the blend was used, which can be explained by a higher capillary pressure. A special case was observed in cores with 10% clay content (Keuper), where the baseline experiments using brine exhibited a high standard deviation. We attribute this behavior to the large mineralogical heterogeneity of the Keuper cores and the heterogeneous distribution of clays and mineralogical impurities. Both the blend and the surface-modified nanoparticles managed to restore a water-wet state, and additional promising recoveries were up to 65% in the case of strong oil-wetness. Nano-EOR is an embryonic technology; hence, literature data is scarce on how oil composition and reservoir mineralogy could influence its use to obtain additional recovery and maximize benefits. Our systematic workflow, helps understanding the parameters that require detailed evaluation in order to forecast recoveries for field tests. The experimental synergies provide a good approach to evaluate fluid-fluid and rock-fluid interaction.

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

This paper investigates the additional oil recovery associated to viscoelastic flow instabilities encountered during polymer flooding. Single and two-phase polymer EOR experiments were conducted in micromodels that resemble porous media. To set a benchmark for non-viscoelastic flooding processes, Polystyrene Oxide (PEO) experiments are presented as well. The experimental workflow consists of three main steps. First, saturation of the micromodel with a synthetic oil. Second, displacement of synthetic oil by an aqueous PEO solution. Third, displacement of the remaining oil by a viscoelastic polymer solution. For evaluation purposes, viscosity of the polymer and polystyrene oxide solution are approximately matched. Furthermore, tracer particles are attached to the aqueous phase to enable high quality streamline visualization. The streamline data is gathered using a highspeed camera mounted on an epifluorescence microscope. In this study we demostrate that viscoelastic flow instabilities are highly caused and influenced by polymer properties. It is also shown flow instabilities dependence on pore space geometry and Darcy's velocity. We have observed a dependency of elastic turbulence on mechanical degradation, polymer concentration and solvent salinity. Furthermore, two-phase flood experiments in complex pore-scale geometries have confirmed that elastic flow inconsistency provides a mechanism capable of increasing oil phase mobilization by the viscoelastic aqueous phase. Due to high resolution particle tracing in the micromodels, the main causes of enhanced mobilization can be described as: (1) Moffatt vortices, (2) crossing streamlines, especially near grain surfaces and (3) steadily changing flow directions of streamlines. Thus, by adding viscoelastic additives to injection fluids and considering a sufficient shear rate, even a creeping flow is able to further enhance the displacement process in porous media by its elastic instabilities. This work provides an adittional understanding of pore-scale polymer displacement processes, namely oil mobilization due to elastic turbulence/flow instabilities. Using the potential of state-of-the-art micromodels enables to conduct high quality streamline visualization which is the key to an improved polymer EOR screening. Thereby enables to understand which properties of viscoelastic solutions contribute to oil recovery. Moreover, this analysis can be used to modify subsequently the fluid characteristics in order to achieve an optimized process application.