This work aims at studying the origin of spontaneous emulsification occurring at the oil/water interface. This phenomenon was observed for the five crude oils tested as well as at the interface of an asphaltene toluene mixture and water. The kinetics of appearance of water micro-droplets was slowed down for increasing salt concentrations and the micro-droplet formation ceases when the chemical potential of water they contain is equal to the one of the water in the bulk solution. Nucleation events occur at the oil-water interface and at the solid surface/liquid interface: some water microdroplets are stuck together close to the oil/water interface, others grow in oil and sediment or nucleate at the oil/solid surface. This suggests the following mechanism: water molecules diffuse from the water reservoir into the oil phase, and then create droplets. These droplets are simultaneously fed by hydrosoluble "osmogeneous" species increasing the osmotic pressure, inducing an osmotic pumping of water molecules into micro-droplets WATER OIL

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Summary It is now common knowledge among enhanced-oil-recovery (EOR) practitioners that the combination of ferrous iron (Fe2+) and dissolved oxygen (O2) causes severe oxidative degradation to EOR polymers, resulting in a lowering of molecular weight (MW) and hence, a loss of viscosity. During the design of polymer-flooding projects, an important question is thus the acceptable levels of Fe2+ and O2 that can be tolerated in injection-water specifications. Furthermore, we would like to be able to predict the extent of degradation in the case of excess Fe2+or oxygen ingress. However, despite more than 50 years of research and a general understanding of the degradation mechanism involved, quantitative prediction of the extent of degradation has proved elusive and dependent on the measurement protocol. This is likely because of the fastidious experimental protocols required to work under anaerobic or limited-oxygen conditions. We examine existing protocols and demonstrate that experiments in which either Fe2+ or O2 is the limiting reagent yield equivalent results when the stoichiometry of the Fe2+ autoxidation reaction with oxygen is taken into account. On the basis of these findings, a novel, easy approach is proposed to quantify polymer-oxidative degradation as a function of either O2 or Fe2+ content. The limits of 225 ppb Fe2+ and 32 ppb of O2 are fixed for Flopaam 3630S in 6 g/L brine in the concentration range 500–1,500 ppm to ensure that degradation of low-shear plateau viscosity does not exceed 10%. Higher levels will lead to severe polymer degradation. The influence of polymer concentration, temperature, and salinity is also investigated. At last, evolution of redox potential and pH during Fe2+ oxidation is discussed along with the injectivity risk associated with the formation of Fe3+. There is a direct practical application of these findings for the design of surface facilities for polymer dissolution and transport and for the prediction of degradation in case of oxygen ingress. Moreover, a simple and easily performed protocol is proposed for the evaluation of polymer oxidative degradation for any given field conditions.

In microchannels, the stability of a fluid jet injected into another immiscible fluid strongly depends on its degree of geometric confinement. When the width of the jet, w, is larger than the channel height, H, the surface tension driven Rayleigh-Plateau instability is suppressed so that the 2D (bidimensional)-confined jet is absolutely stable and never collapses into bubbles (or drops) in contrast to what occurs when w{less than or equal to}H. We here demonstrate both experimentally and theoretically, that this picture is indeed no longer valid when Marangoni effects are considered. We experimentally show that the addition of small length alcohol molecules into the liquid phase destabilizes a 2D-confined gas-water microfluidic stream (w>H) leading to the generation of steady non-linear waves and further to the production of bubbles. Using a simple hydrodynamic model, we show through a linear analysis that the destabilization of the gas stream may result from a Marangoni instability due the fast adsorption of the alcohol molecules which occurs on a time scale comparable to that of the microfluidic flow.

Performing Surfactant-Polymer (SP) flooding in High Salinity and High Temperature (HS-HT) conditions - up to 297 g/L TDS formation brine and 105°C-120°C - is challenging, both as regards the products selection and the implementation of the experimental workflow, from the selection tests of the surfactants and polymers to the corefloods, which need to be performed in an oxygen-free environment to reproduce field test conditions. In this work, we show our recent lab developments of SP formulations for different HS-HT conditions for limestone and sandstone reservoirs, both in terms of efficiency of chemicals in such conditions, and technical aspects. Specific polymers and surfactants have been selected based on chemical stability and efficiency. The main surfactants have been chosen in the ethoxylated carboxylates and ethoxylated sulfonates series, and they have been formulated in order to reach optimal salinities in the 80-130 g/L TDS range. Special attention has been paid to the impact of the divalent cations on the physicochemical behavior. These surfactant formulations were tested in corefloods using SAV10 as thermally stable polymer and taking into account the change in physicochemical phase behavior with oil saturation. Corefloods were carried out in oxygen-free conditions as well as pipettes study and surfactant thermal stability tests, since polymer and surfactants degrade in presence of oxygen at such high temperature. Our results show a good efficiency of the formulations based on ethoxylated sulfonates on limestones (Residual oil saturation (Sorc) ~9%) with a retention of 0.26 mg/g of rock, whereas formulations based on ethoxylated carboxylates performed well on quartz sandpack (Sorc ~ 1-5%). The latter however gave lower recovery and high retention on limestones. This work describes the development workflow and testing procedures to operate chemical EOR in very harsh conditions. As a result, we demonstrate that efficient HS-HT SP formulations are now available.

In 2014, Total performed a surfactant-polymer single-well pilot to test the effectiveness of a surfactant formulation developed in-house, and including a new proprietary class of surfactants with improved temperature- and salinity-tolerance characteristics. This paper unveils the results of this pilot which targeted a high temperature, high salinity carbonate reservoir. The operations were performed on an oil bearing reservoir of Lower Cretaceous age, in an offshore field operated by Total since 1974 and located 180 km offshore Abu Dhabi. Dedicated topsides were designed and installed for this EOR project. Extensive in-house laboratory studies were performed to select and synthesize the chemicals. Specific simulations, using laboratory results as input, were carried out to predict the pilot performance, design the Single Well Tracer Tests (SWTTs), and size the equipment. In this paper we will discuss the workflow used to select the most appropriate well and present the methods and results used to characterize the reservoir. Then we will relate it to the surfactant-polymer injection field operations. Finally the reservoir monitoring activities that were necessary to preserve reservoir integrity and demonstrate the pilot efficiency will be described. The strong decrease in remaining oil saturation measured after the chemical EOR pilot clearly proves the effectiveness of the chemicals synthesized by Total to mobilize the remaining immobile oil after water-flood. These positive outcomes change the perception of CEOR in hot, saline Middle-East carbonate reservoirs, and could be a "game changer".

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This article describes the formulation design, optimization, implementation, and lessons learned leading up to a successful 1-spot surfactant-polymer (SP) pilot in the Middle East. The target field is a high-temperature, high-salinity, low-permeability carbonate, and thus presents both great challenges and great potential for the application of chemical EOR technology. A surfactant-polymer (SP) formulation was optimized for these conditions based upon a novel, hydrophilicity-enhanced molecule for high-temperature, high-salinity reservoirs synthesized by Total R&D labs. Thermal stability tests, over 5000 microemulsion pipette tests, and more than 40 corefloods were performed during the screening and optimization process leading up to the 1-spot SP pilot. Additionally, a novel method was developed to optimize polymer molecular weight distribution, in order to decouple in-situ viscosity from near-wellbore injectivity. The final formulation consists of a 0.4 pore volume (PV) SP slug of 1.35% active surfactant, plus 1% clarifier, and SAV-225 polymer (SNF Floerger) in a 80 g/l brine corresponding to a hypothetical softened mixture of seawater and local aquifer water. This is followed by a polymer drive of AN-125 polymer (SNF Floerger) in softened seawater, such that a negative salinity gradient is imposed between the 230 g/l formation brine, 80 g/l SP slug, and 42 g/l seawater. The formulation was designed and implemented without need for a preflush. Residual oil saturation to chemicals (Sorc) in analog limestone cores was measured as 5%±2%, corresponding to a recovery factor (RF) of 90%±4%. Reservoir limestone contains significant heterogeneity on the core-scale, likely preventing the formation of an oil bank, and thus yielded lower recoveries (Sorc: 13%±2%, RF: 84%±4%). One-spot pilot recovery corresponded closely to recovery in analog cores (Sorc: 4%, RF = 90%, Al-Amrie et al., 2015), suggesting that the reason for the lower recovery in reservoir cores was in fact due to the short core length with respect to the mixing zone, as suggested in a previous publication (Levitt et al., 2012).