Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray. Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties. Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated. An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability. Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate. The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution. Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough. These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front. The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths. This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.

New methods are continuously being evaluated for Enhanced Oil Recovery (EOR). Nanoparticle flooding is an intriguing new approach in which one of the main applications is microscopic diversion. Linked polymer solution (LPS) is a nanoparticle system that consists of partially hydrolyzed polyacrylamide (HPAM) cross-linked by aluminum(III). The source of aluminum is an aluminum citrate (AlCit) complex, where citrate serves as a carrier ligand. The large size and flexibility of HPAM as well as the multicomponent species of AlCit present at most relevant reservoir conditions make the system highly complex and challenging to characterize. In the literature, there is a lack of systematic and consistent data describing the various chemical species involved in LPS. This work used nuclear magnetic resonance (NMR) spectroscopy and dynamic rheology to investigate the reaction between HPAM and Al 3+ as a function of solution pH. The results of NMR spectra indicate that AlCit is more reactive at near neutral pH and cross-linking reactions should preferably be performed at this condition. Structural conformation and viscoelastic properties of the HPAM-Al complex appear to be dominated by the protonation−deprotonation state of the carboxylic acid groups as result of pH changes.

There is booming interest in the application of nanoparticles for enhanced oil recovery. In this work, a polymer nanoparticle that is generated by cross-linking a high-molecular weight partially hydrolyzed polyacrylamide with aluminum­(III) and known as linked polymer solution (LPS) has been studied. The size and conformational state of LPS particles are influenced by the concentration of Al­(III). To the best our knowledge, there is no current established method for determining the conformational state, i.e., single coiled particle, coil aggregates, or gel, for a polymer solution with a high molecular weight (>10 × 106 Da) and a low concentration (<1000 ppm). In this work, therefore, the phase transition of LPS is investigated by employing two-dimensional 1H–1H nuclear magnetic resonance (nuclear Overhauser effect spectroscopy and diffusion ordered spectroscopy), UV–visible spectroscopy, and oscillatory rheological methods. Each method is limited to determining the conformational state; however, the combined methods provided a consistent tool for mapping various interactions regarding the conformational changes of LPS as a function of Al­(III) concentration. The results of our study revealed that the phase transition is a stepwise process; the transition from a random polymer coil to structured coils (intramolecular cross-linking) was observed by reduction of the hydrodynamic radius and an increase in the rate of diffusion, followed by coil aggregates as a function of Al3+ concentration. Ultimately, networked weak gels are formed by coil aggregates (intermolecular cross-linking) above the threshold concentration.

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Linked polymer solution (LPS) is a nanoparticle polymer and designed by crosslinking a high molecular weight partially hydrolyzed polyacrylamide (HPAM) with aluminum (III). It has been applied in the oil industry to enhance oil recovery by improving sweep efficiency and by microscopic diversion in porous media. To achieve good propagation properties, aggregates formed by intermolecular crosslinking and gel formation should be avoided. To our knowledge, there is no established method to distinguish between intra‐ and intermolecular crosslinking for high molecular weight (>10 × 106 Da), low concentration (<1000 ppm), polydisperse solutions of partially hydrolyzed polyacrylamides in high salinity solvents (5 wt % NaCl). The high salinity solvent is relevant to represent for formation water in many oil reservoirs. The main objective of the present study is to establish an experimental method for determining phase transition of LPS from monomeric coiled state to aggregated state in a high salinity solvent. No single experimental methods are conclusive and we have therefore applied a combinatorics approach including two‐dimensional NMR, dynamic rheology, and UV spectroscopy. The different techniques show similar trends, which allow overall interpretations of phase transitions to be made. The experimental results indicated that the LPS solution at high salinity solvent underwent a phase transition by chain re‐expansion, called reentrant transition. The transition point was observed at addition of 100 ppm of Al3+. Higher concentrations of Al3+ suppressed the rate of reentrant transition, most likely because of intramolecular crosslinking of HPAM chains by Al3+. Intermolecular crosslinking reaction was not observed at these conditions. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2016, 133, 43825.

Salt caverns have been successfully used for natural gas storage globally since the 1940s and are now under consideration for hydrogen (H2) storage, which is needed in large quantities for the Green Shift. Salt caverns are not sterile, and H2 is a ubiquitous electron donor for microorganisms. This could entail that the injected H2 will be microbially consumed, leading to a volumetric loss and potential production of toxic H2S. However, the extent and rates of this microbial H2 consumption under high-saline cavern conditions are not yet understood. To investigate microbial consumption rates, we cultured the halophilic sulphate-reducing bacteria Desulfohalobium retbaense and the halophilic methanogen Methanocalcus halotolerans under different H2 partial pressures. Both strains consumed H2, but consumption rates slowed down significantly over time. The activity loss correlated with a significant pH increase (up to pH 9) in the media due to intense proton- and bicarbonate consumption. In the case of sulphate-reduction, this pH increase led to dissolution of all produced H2S in the liquid phase. We compared these observations to an original brine retrieved from a salt cavern located in Northern Germany, which was incubated with 100% H2 over several months. We again observed a H2 loss (up to 12%) with a concurrent increase in pH up to 8.5 especially when additional nutrients were added to the brine. Our results clearly show that sulphate-reducing microbes present in salt caverns will consume H2, which will be accompanied by a significant pH increase, resulting in reduced activity over time. This potentially self-limiting process of pH increase during sulphate-reduction will be advantageous for H2 storage in low-buffering environments like salt caverns.

Salt caverns have been successfully used for natural gas storage globally since the 1940s and are now under consideration for hydrogen (H2) storage, which is needed in large quantities to decarbonize the economy to finally reach a net zero by 2050. Salt caverns are not sterile and H2 is a ubiquitous electron donor for microorganisms. This could entail that the injected H2 will be microbially consumed, leading to a volumetric loss and potential production of toxic H2S. However, the extent and rates of this microbial H2 consumption under high-saline cavern conditions are not yet understood. To investigate microbial consumption rates, we cultured the halophilic sulphate-reducing bacteria Desulfohalobium retbaense and the halophilic methanogen Methanocalculus halotolerans under different H2 partial pressures. Both strains consumed H2, but consumption rates slowed down significantly over time. The activity loss correlated with a significant pH increase (up to pH 9) in the media due to intense proton- and bicarbonate consumption. In the case of sulphate reduction, this pH increase led to dissolution of all produced H2S in the liquid phase. We compared these observations to a brine retrieved from a salt cavern located in Northern Germany, which was then incubated with 100% H2 over several months. We again observed a H2 loss (up to 12%) with a concurrent increase in pH of up to 8.5 especially when additional nutrients were added to the brine. Our results clearly show that sulphate-reducing microbes present in salt caverns consume H2, which will be accompanied by a significant pH increase, resulting in reduced activity over time. This potentially self-limiting process of pH increase during sulphate-reduction will be advantageous for H2 storage in low-buffering environments like salt caverns.

Polymer flooding has been a successful EOR method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging due to adsorption loss and polymer availability for high temperature, high salinity (HTHS) reservoirs. In this study, polymer flooding for carbonate reservoirs is moved forward as we show that HTHS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultra-high salinity conditions. Carbonate reservoir core plugs with permeabilities ranging from 10 mD to Darcy range were used for the adsorption/dynamic retention studies. The dynamic retention experiments made use of water-soluble tracers as comparison for the polymer transport in porous medium. The synthetic formation water had ultra-high salinity, i.e. 180 000 mg/L TDS with a hardness of 19 %. In addition to experiments performed on single phase water saturated cores, experiments were also performed on crude oil aged reservoir core samples. The aged core samples were flooded to Sorw by water flood or by centrifugation. The implementation of polymer flooding in carbonate reservoirs has long been restricted due to adsorption and retention. Most polymers for Enhanced Oil Recovery (EOR) are negatively charged. It has long been assumed that the rock surface is primarily positively charged in carbonate rock. The argument of electrostatic attractive forces indicates high loss of polymer due to adsorption. However, the rock surface charge in carbonates may vary with presence of surface biofilms, oil layers and highly varying pore geometries. Measurements of surface charge have shown that this assumption has been too simplistic and that some surfaces are negatively charged or near-neutral due to earlier mentioned effects or ion composition, hardness and total ionic strength. Furthermore, wettability is a key factor. The results of the retention experiments on aged carbonate reservoir rock, show that retention is reduced by a factor of 4-6 when remaining oil is present. This is highly surprising when the ultra-high salinity (180 000 ppm TDS) is considered. The paper shows detailed analysis of retention experiments and discusses the influence of oil, salinity, and polymer chemistry on retention in carbonate rock. Retention is a key factor for implementation of polymer flooding in carbonate reservoirs. This study shows that new, commercially available HTHS polymers can be applied for polymer flooding in carbonate reservoirs without a high loss of chemicals. The results obtained show a positive impact on economic feasibility of polymer EOR in carbonates. The solutions found here can be applied to similar reservoir conditions and facilitate polymer flooding in HTHS carbonate reservoirs. Pilot tests based on these results are ongoing at the time of writing.