B.J. Bourbiaux

Bio: B.J. Bourbiaux is an academic researcher from Institut Français. The author has contributed to research in topics: Fracture (geology) & Diffusion (business). The author has an hindex of 8, co-authored 11 publications receiving 487 citations.

Experimental study of cocurrent and countercurrent flows in natural porous media

Abstract: This paper reports flow experiments involving cocurrent and countercurrent spontaneous water/oil imbibition performed on the same laterally coated sample of a natural porous medium with local saturation measurements and various boundary conditions. The experiments with countercurrent imbibition showed slower oil recovery, a smoother water/oil front, and slightly lower ultimate oil recovery than those with predominantly cocurrent imbibition. Numerical simulations revealed that the relative permeabilities that enabled good prediction of countercurrent oil recovery rate are about 30% less than the conventional cocurrent relative permeabilities at a given water saturation. Viscous coupling is assumed to be the origin of this difference. A new formulation of Darcy equations that uses a matrix of mobilities was found to be in qualitative agreement with experimental results.

Predicting gas-condensate reservoir performance: how flow parameters are altered when approaching production wells

Abstract: Describing flow processes occuring both far from and close to the wellbore region is a major concern to accurately predict gas-condensate reservoir performance. This requires the knowledge of the gas-condensate parameters, e.g. the critical liquid saturation Slc and the gas-condensate relative permeabilities krg and krl. Regarding their determination, this paper addresses two main questions: (1) Can analog fluid systems be used instead of real ones to measure gas-condensate flow parameters ? (2) What flow rate dependence must the relative permeabilities account for to properly describe the high flow rate conditions that prevail in the wellbore region ? To acquire flow parameters representative of the inner part of the reservoir, an integrated procedure was used to measure Slc's and kr curves. 29 flow tests were performed in an outcrop clayey sandstone core and 2 in an outcrop chalk core, using as gas-condensate systems, a binary C1C3, a ternary C1C3C7 and finally an actual North Sea reservoir fluid. Slc's for both analog and real fluid systems were found to increase with γ. For relative permeabilities under the low flow rate conditions that were used, no γ dependence of the kr curves was put into evidence. This was explained on the basis of a dependence upon a macroscopic capillary number CA that allows to compare viscous to capillary forces. Using this dimensionless number and considering a CA - dependence of the relative permeabilities leads to reconcile variations of relative permeabilities with y and flow rate as described in the literature. Finally, this paper discusses what characteristics relative permeabilities should display so as to properly model wellbore flow conditions.

A Fast and Efficient Methodology to Convert Fractured Reservoir Images Into a Dual-Porosity Model

Abstract: La caractŽrisation et la simulation dynamique des rŽservoirs naturellement fracturŽs ont bŽnŽficiŽ d'avancŽes importantes ces dernires annŽes. Toutefois, l'ingŽnieur rŽservoir reste confrontŽ ˆ la difficultŽ de paramŽtrer le modle Žquivalent ˆ double porositŽ utilisŽ pour reprŽsenter de tels rŽservoirs. En particulier, les permŽabilitŽs de fracture Žquivalentes et les dimensions du bloc matriciel Žquivalent ne peuvent pas tre facilement dŽduites de l'observation des images complexes de rŽseaux naturels de fractures. Cet article dŽcrit une technique nouvelle et systŽmatique pour calculer ces paramtres Žquivalents. Les rŽsultats de sa mise en Ïuvre au moyen d'un logiciel spŽcifique dŽmontrent sa validitŽ et son efficacitŽ pour l'Žtude de cas de champ. Un tenseur des permŽabilitŽs de fracture Žquivalentes est dŽduit de calculs d'Žcoulements stationnaires et monophasiques dans le rŽseau rŽel de fractures, ce dernier Žtant assimilŽ ˆ un rŽseau 3D de rŽsistances et soumis ˆ des conditions aux limites spŽcifiques. Les dimensions du bloc Žquivalent dans chaque couche sont obtenues rapidement par identif ication d'une fonction gŽomŽtrique reprŽsentative d'un dŽplacement capillaire. La mŽthodologie a ŽtŽ validŽe par comparaison avec des simulations ˆ maillage fin rŽalisŽes au moyen d'un simulateur de rŽservoir conventionnel. Puis, une image complexe d'affleurements d'une formation de grs a ŽtŽ traitŽe ˆ titre de dŽmonstration. L'outil innovant associŽ ˆ cette mŽthodologie donne la possibilitŽ ˆ l'ingŽnieur rŽservoir de construire un modle ˆ double porositŽ qui reproduit de faon plus fidle le comportement hydraulique du milieu rŽel fracturŽ.

Recovery of oil by spontaneous imbibition

Abstract: Spontaneous imbibition is of particular importance to oil recovery from fractured reservoirs. There has been a surge in the growth of technical literature over the past 5 years. This review is centered on developments in the scaling of laboratory imbibition data. Results for variation in interfacial tension, wetting and non-wetting phase viscosity, sample size, shape and boundary conditions, and initial wetting phase saturation have been correlated for a variety of strongly water-wet rocks as plots of normalized oil recovery vs. dimensionless time. Correlations have been tested for weakly water-wet conditions induced by adsorption from crude oil. In situ fluid saturation measurements have been used to distinguish between modes of imbibition that range from frontal to global displacement. Research on surfactant-enhanced imbibition has advanced from laboratory to field tests.

Multiphase Flow in Permeable Media: A Pore-Scale Perspective

Abstract: Hydrocarbon production, gas recovery from shale, CO2 storage and water management have a common scientific underpinning: multiphase flow in porous media. This book provides a fundamental description of multiphase flow through porous rock, with emphasis on the understanding of displacement processes at the pore, or micron, scale. Fundamental equations and principal concepts using energy, momentum, and mass balance are developed, and the latest developments in high-resolution three-dimensional imaging and associated modelling are explored. The treatment is pedagogical, developing sound physical principles to predict flow and recovery through complex rock structures, while providing a review of the recent literature. This systematic approach makes it an excellent reference for those who are new to the field. Inspired by recent research, and based on courses taught to thousands of students and professionals from around the world, it provides the scientific background necessary for a quantitative assessment of multiphase subsurface flow processes, and is ideal for hydrology and environmental engineering students, as well as professionals in the hydrocarbon, water and carbon storage industries.

Pore-scale investigation of viscous coupling effects for two-phase flow in porous media.

Abstract: Recent studies have revealed that viscous coupling effects in immiscible two-phase flow, caused by momentum transfer between the two fluid phases, can be important in porous medium systems. In this work, we use a three-dimensional parallel processing version of a two-fluid-phase lattice Boltzmann (LB) model to investigate this phenomenon. A multiple-relaxation-time (MRT) approximation of the LB equations is used in the simulator, which leads to a viscosity-independent velocity field. We validate our model by verifying the velocity profile for two-phase flow through a channel with a square cross section. We then simulate co-current flow through a sphere-pack porous medium and obtain correlations of the relative permeabilities as a function of capillary number, wettability, and the fluid viscosities. The results are qualitatively consistent with experimental observations. In addition, we calculate the generalized permeability coefficients and show that the coupling coefficients are significant and the matrix is nonsymmetric. We also find a strong correlation between the relative permeability and interfacial area between fluids, indicating that both the common extension of Darcy's Law and the generalized formulation accounting for viscous coupling effects do not provide adequate insight into two-phase flow processes in porous media. This work lends additional support for the hypothesis that interfacial area is a key variable for multiphase flow in porous medium systems.