Search

An extensive laboratory study was conducted to measure the interfacial tension (IFT) between CO 2 and brine consisting in equal molal concentrations of NaCl and CaCl 2 . The experiments were repeated at various pressures, temperatures and salinities that are representative of conditions prevailing during CO 2 storage in deep saline aquifers. The dependence of CO 2 /brine IFT on pressure and temperature is similar to that previously reported for the systems: CO 2 /NaCl solution and CO 2 /CaCl 2 solution. CO 2 /brine IFT increases linearly with water salinity and the magnitude of this increase was found equal to the sum of the individual CO 2 /NaCl solution and CO 2 /CaCl 2 solution IFT increments, indicating a strong additive effect on IFT when the brine is composed of various salts.

The effectiveness of CO2 storage in deep saline aquifers and hydrocarbon reservoirs is governed, among other factors, by the interfacial tension between the injected CO2 and formation water (brine). Experimental data on CO2/water and CO2/NaCl solution have revealed that the interfacial tension depends on the pressure, temperature and water salinity. However, there is still a lack of data for other salts (such as MgCl2 and CaCl2) which are also present in aquifers and carbonate reservoirs. In the present work, the interfacial tension (IFT) of the system CO2/CaCl2 solution is measured under pressures, temperatures and salinities which are relevant to storage conditions. The evolution of CO2/CaCl2 solution IFT with pressure and temperature is similar to that reported for CO2/water and CO2/NaCl solution systems and increases linearly with salinity. When correlating the measured IFT with the salt concentration, it looks that the IFT increase, due to salt concentration, is proportional to the cation valence.

At the end of the secondary recovery in water-wet reservoirs, the remaining oil saturation might be high due to capillary trapping of the oil ganglia within the micro-structure of the rock. However, this trapped oil can be produced if the capillary barrier is suppressed by surfactant injection. To characterize this phenomenon, the Capillary Desaturation Curve (CDC : the residual oil saturation in a rock sample as a function of the trapping number Nt (sum of the Capillary and Bond numbers)) needs to be evaluated experimentally. This measure constitutes an important input parameter in chemical EOR flooding for screening and simulation. In this work, we investigated experimentally the relation between CDC and microscopic properties at the pore scale : the oil ganglia size distribution and the porous structure. Experiments were performed on a set of water-wet sandstones with different petrophysical properties. Computed Tomography imaging (CT-Scan) was used to accurately measure the mean residual oil saturation and the local saturation distribution at the plug scale (macro scale). Oil ganglia size-distribution as well as pore geometrical properties were also quantified using high resolution micro-CT images at the pore scale. The effect of trapped oil on water relative permeability is also discussed. Results showed how the CDC depends on the pore structure and is strongly related to the oil ganglia size distribution at residual oil saturation. We show that based on those microscopic properties the Capillary Desaturation Curve measured on the macro plugs can be directly predicted. We show also that in this regime of oil ganglia mobilization the water relative permeability has a specific scaling with the trapping number.

We carried out experiments to study the effect of wettability heterogeneities on: (1) displacement mechanisms, (2) sweep efficiency and (3) trapped oil quantities and fluid distribution in three-phase gas injection and developed a theoretical simulator. Secondary gas injection experiments was conducted in transparent glass micromodels of heterogeneous wettability. Oil-wet patches in a water-wet matrix were obtained by selective silane grafting on the glass surface. Different heterogeneity patterns were considered for the same oil-wet over water-wet surface ratio. Displacement sequences were video-recorded and fluid saturations determined by image analysis. A theoretical model of three-phase flow in a porous structure was developed. In this model the porous medium is simulated as a network of interconnected pores. The model permits an imposition of heterogeneous wettability by assigning different water-oil contact angles according to the desired wettability pattern. The calculation of flow within the network takes into account the flow of oil through wetting and spreading films and the displacement mechanisms observed in the transparent micromodels. Comparison between experimental results and simulations shows that the size and distribution of wettability heterogeneities strongly affects microscopic and macroscopic behaviour during gas injection.

Surfactant flooding is one of the effective technologies to enhance oil recovery of water flooded petroleum reservoirs. Several previous studies have demonstrated that the release of oil from a rock submitted to waterflood depends on the competition between displacing forces (viscous and buoyancy) and capillary forces. This competition is expressed by two dimensionless numbers, the Capillary number, defined as the ratio of viscous to capillary forces and the Bond number, defined as the ratio of gravity to capillary forces. At the core scale the evolution of the oil residual saturation as function of the capillary number is better known as the Capillary Desaturation Curve (CDC), which constitutes an important input parameter in EOR processes reservoir simulation. In this work we present a new experimental workflow to investigate the effect of rock structure on the CDC. This workflow combines core flood experiments and CT-scan imaging to accurately measure the mean residual oil saturation at different capillary number values as well as the local saturation distribution along the core plug. The CDC was measured on a set of water-wet sandstone with different permeability and degree of heterogeneity. The capillary number was varied by injecting a surfactant solution at different flow rates. Using this methodology, we first study the effect of core flood orientation (Horizontal injection and vertical downflow injection). The resulting local saturation curves show that in a horizontal configuration the oil migrates upwards in the sample inducing an oriented front strongly deviating from the piston like displacement, and very different from the one observed in the vertically placed sample. This behaviour is manly attributed to buoyancy forces that are no more negligible compared to capillary forces when surfactant is injected. This experiment shows that when measuring a CDC the capillary number needs to be corrected to take into account the buoyancy forces. In a second step we have investigated the effect of local heterogeneity of core plugs on the CDC with Clashach and Fontainebleau sandstones. Two samples of Clashash sandstone with equivalent mean properties were studied (mean permeability of 380 and 426 md and mean porosity of 13.4 % and 14.1% respectively). The resulting CDC curve exhibits almost two decades difference in the critical capillary number. This discrepancy is explained in terms of the local variation of the porosity that induces important differences in the local saturation profile.

The role of the viscosity ratio κ during forced imbibition in porous media is investigated theoretically using a new simulator, and experimentally based on displacements in model pore networks. Both theory and experiment show that κ is an important parameter of microdisplacement in porous media, not only for intermediate and large capillary number values, but also for small values, say Ca -6 . In the latter region the residual nonwetting saturation S or is virtually independent of Ca for κ 1. The unexpected result is that, even for very small values of Ca, S or decreases appreciably as κ decreases, especially in the case of very good wettability. Simulations indicate that the effect of κ on S or for low Ca values is enhanced as the contact angle decreases. The phenomenon is attributed to a synergistic effect between capillary microfingering and localized viscous forces. It must be emphasized that the velocity gradients which are created locally by the advance of a single meniscus, or of a wetting film, are sufficiently large to make viscous stresses important, even when the Ca value of the macroscopic flow is very low (say, of order 10 -8 ). A favorable viscosity ratio reduces the extent of capillary microfingering and thus increases the efficiency of microdisplacement, despite the fact that for Ca -6 the viscous stresses are negligible on a macroscopic scale. Further work is needed to analyze the synergism between κ and θ e at low Ca values.

Water Alternating Gas (WAG) processes promise optimized results in applications such as CO2 storage in reservoir rocks, enhanced oil recovery or soil remediation. In this kind of processes, hysteretic phenomena take place due to imbibition/drainage processes or to varying wettability affecting the three-phase relative permeabilities. The optimization of WAG process requires improving the predictive capabilities of current three-phase relative permeability models. In order to emphasize the impact of relative permeability hysteresis on the numerical simulation of WAG injection a series of experiments were performed : injection of nitrogen at residual oil saturation, WAG experiment at ambient conditions, WAG experiment at reservoir conditions. The experiments were then simulated with three available methods : Carlson's hysteretic model and Stone2, Killough's hysteretic model and Stone1 and the three-phase hysteretic fractal model (SPE 65127). The three models were applied and compared with the experimental results and the three-phase fractal hysteretic model which solely applies to both WAG ambient and WAG reservoir conditions was successfully used.

A16 Injectivity Impairment Due to Dissolution/ Precipitation Processes During a CO2 Injection J.-M. Lombard* (Institut Francais du Petrole) P. Egermann (Institut Francais du Petrole) O. Vizika (Institut Francais du Petrole) S. Bekri (Institut Francais du Petrole) & B. Bazin (Institut Francais du Petrole) SUMMARY Keeping the well injectivity over the lifetime of CO2 geological storage operations is crucial for the environmental technical and economical success of such projects. The specificity of a CO2 injection compared to a conventional hydrocarbon gas injection is the possibility for geochemical reactions to occur between the mobile reactive brine and the host formation. This leads

A proper modeling of tertiary recovery processes such as gas injection or WAG (Water Alternating Gas) requires an adequate three-phase flow model. This allows to better predict the recovery efficiency, gas storage reservoir performance as well as the well injectivity. For gas drainage, a previous paper [25] presented a new three- phase flow model based on a theoretical analysis and validated through experimental approach. For WAG injection, there is an additional complexity due to the need to model the imbibition that occurs when gas saturation decreases. To tackle the modeling of hysteresis problem, a comprehensive approach was followed. First, successive drainage and imbibition experiments were conducted under various conditions of initial saturations. A new three-phase model taking into account the hysteresis is presented and validated on the experiments. Indeed, as shown in previous experimental studies, hysteresis was found to depend not only on the drainage/imbibition process (saturation history) but also on the cycle considered (displacement history) where cycle names the association of two consecutive displacements (drainage and imbibition). In this study, a relevant analytical expression of the hysteresis is proposed avoiding any negative effect of numerical instabilities. The new formulation was implemented in a reservoir simulator and WAG experiments have been successfully simulated. The impact on breakthrough time, overall recovery efficiency was tested through large scale reservoir simulations.

Depressurization of a virgin or waterflooded oil reservoir results in the appearance of a solution gas saturation. Above a saturation threshold, this gas becomes mobile and can be produced. Knowledge of the critical gas saturation (Sgc) and the subsequent relative permeabilities (Kr) in the far field and the near-wellbore region has a tremendous impact on gas and oil production forecasts. The present paper provides a new methodology to obtain representative Kr and Sgc values for a depressurization process. Specific experiments are presented in which undersaturated oil was injected upstream at a fixed rate whereas downstream the pressure was controlled in order to reproduce a drawdown. Evolution of pressure was recorded and in-situ gas saturations measured by CT-scanner. Two initial conditions were considered, fully oil saturated and at irreducible water saturation. Influence of the drawdown scheme was also explored. Transient evolution of the gas saturation profile in the core is clearly shown. Kr are deduced from history matching. They are finally compared to the Kr derived from gas injection experiments. It is demonstrated that gas/oil Kr shape is strongly affected by the way the gas appears and is distributed in the porous medium. For solution gas drive, oil relative permeability is higher and gas relative permeability is smaller than for gas injection. Concerning critical gas saturation, the experiments show two types of gas mobility depending on the operational conditions: mobility threshold attained from connection of bubbles or from mobilization of a population of separate bubbles. For the first type, Sgc can be linked to the values obtained through static experiments at fixed depletion rate.

When an electric field is applied to a drop suspended in another liquid the drop deforms. The relation between the applied field and the mode and magnitude of the deformation have been studied extensively. Nevertheless, Torza, Cox & Mason (1971) found that quantitative agreement between the leaky dielectric theory (Taylor 1966) and experiment is quite poor. Here we describe results from a new series of experiments. Drops suspended in weakly conducting liquids were deformed into spheroids with both steady and oscillatory fields. Drop deformation, interfacial tension, and the electrical properties of the fluids were measured for each system to provide a definitive test of the theory. The agreement between the leaky dielectric model and our results for drop deformations in steady fields is much improved over previous results, although discrepancies remain for some systems. Drop deformations in oscillatory fields consist of steady and oscillatory parts because of the quadratic dependence on the field strength. Measurements of the steady part at 60 Hz, where the oscillatory deformation is negligible, are in excellent agreement with the theory. The effects of frequency on the steady deformation were studied by measuring oblate deformations at a series of frequencies and field strengths; the agreement with theory is good. Finally, the time-dependent total deformation was measured under conditions where both parts of the deformation are commensurate. Good agreement was found between the measured and predicted maximum and minimum deformations. Nevertheless, only a small range of fluid properties could be studied owing to the need to avoid droplet sedimentation.