Pore scale modeling of capillary pressure curves in 2D rock images
MetadataShow full item record
- PhD theses (TN-IPT) 
Original versionPore scale modeling of capillary pressure curves in 2D rock images by Yingfang Zhou, Stavanger : University of Stavanger, 2013 (PhD thesis UiS, no. 213)
Capillary pressure is relevant to most processes of multiphase flow inporous media, as it controls the pore scale fluids distribution. Reliable capillary pressure curves are required to model and predict larger-scale multiphase flow processes; normally these capillary pressures are obtained experimentally using representative core samples. Besides core scale measurements, pore scale modeling provides another alternative, physically sound approach to compute capillary pressure curves and links the pore scale properties to laboratory measurements. Pore scale modeling is a useful tool to enhance our understanding of capillary phenomena and their impact on microscopic fluid flow in porous media. In this thesis, an existing semi-analytical pore scale model is further developed to compute two- and three-phase uid con gurations and capillary pressure curves at arbitrary wetting conditions in 2D realistic pore spaces that are extracted directly from segmented rock images. The simulated capillary pressure curves and uid con gurations are used as input in an improved interacting tube bundle model to simulate viscosity and capillary-dominated ow in porous media. The dynamic e ects of capillary pressure are further investigated by comparing the equilibrium static capillary pressure and the simulated dynamic capillary pressure curves. Based on this research work, seven research papers have been presented in scienti c journals and international conferences. The main ndings are summarized below: Two-phase capillary pressure curves computed at uniformly-wet conditions can be scaled by the traditional J-function. The imbibition capillary pressure curves and fluid con gurations at mixed-wet conditions depend strongly on the initial water saturation and formation wettability. Based on simulated results, a novel dimensionless capillary pressure function for mixed-wet conditions has been developed to describe more accurately the variability of formation wettability and permeability in reservoir simulation models. In water-wet three-phase systems, capillary entry pressure for the nonwetting phase (e.g., gas or CO2) is strongly a ected by the existing initial fluid con guration of oil and water in the pore space. Generally, the three-phase capillary entry pressure is lower for gas (or CO2) displacing oil than for gas (or CO2) displacing water in a uniform water-wet system, indicating that CO2 is stored more safely below low-permeable formation layers in subsurface aquifers than in depleted oil reservoirs. The simulated three-phase fluid con gurations exhibit a similar behavior as that observed in micro-CT experiments; in spreading systems very thin oillayers are present, while in non-spreading systems only a few relatively thick oil layers exist when gas-oil capillary pressure is low. In the major parts of the three-phase region (except for small oil saturations). The gas-oil capillary pressure at water-wet conditions seems to be described well as a function of only the gas saturation in the major part of the three-phase region, despite three-phase displacements in which gas displaces both oil and water occur frequently in individual pore geometries for the non-spreading systems. At small oil saturations, the gas-oil capillary pressure depends strongly on two saturations, which is particularly visible in the results for the weakly water-wet spreading system because thin oil layers exist after gas has started to invade pores occupied by water only. The simulated saturation pro les under viscous-capillary dominated flow can be explained by the capillary pressure and fluid con gurations, which exhibit increasingly gradual behavior as the contact angle de ned on the oil-wet solid surfaces increases or the initial water saturation decreases. Drainage dynamic capillary pressure curves are located at a higher capillary level than the corresponding static curve, whereas for imbibition the dynamic curve is located at a lower capillary level than the corresponding static one, regardless the porous medium wettability. The simulated dynamic capillary coe cient is a function of saturation and independent of the incremental pressure step, which is consistent with the results rev ported in previous studies. The dynamic coe cient increases with decreasing water saturation at water-wet conditions, whereas for mixed- to oil-wet conditions it increases with increasing water saturation. Imbibition simulations also show that the dynamic capillary coe cient at a constant saturation increases with decreasing initial water saturation at mixed-wet conditions.
PhD thesis in Petroleum engineering
Has partsZhou, Y., Helland, J. O., and Hatzignatiou, D. G. 2011: A model for imbibition in pore spaces from 2D rock images. Extended abstract presented at the Pore2Field International Conference held at IFP Energies nouvelles, Rueill-Malmaison, France, November 16-18, 2011.
Zhou, Y., Helland, J.O., and Hatzignatiou, D.G. 2013. A Dimensionless Capillary Pressure Function for Imbibition Derived From Pore-Scale Modeling in Mixed-Wet-Rock Images. SPE Journal. 18 (2): 296-308. SPE-154129-PA. http://dx.doi.org/10.2118/154129- PA.
Zhou, Y., Helland, J.O. and Hatzignatiou, D.G.: Pore-Scale Modelling of Water Flooding in Mixed-Wet Rock Images: E ects of Initial Saturation and Wettability, SPE Journal. SPE-154284-PA (in press; posted 05 July 2013). http://dx.doi.org/10.2118/154284-PA.
Zhou, Y., Helland, J.O., and Jettestuen, E. 2013. Dynamic Capillary Pressure Curves From Pore-Scale Modeling in Mixed-Wet-Rock Images. SPE Journal. 18 (4): 634-645. SPE-154474-PA. http://dx.doi.org/10.2118/154474-PA.
Zhou, Y., Helland, J. O. and Hatzignatiou, D.G. 2013: Computation of three-phase capillary entry pressures and arc menisci con gurations in pore geometries from 2D rock images: a combinatorial approach, 2013.
Zhou, Y., Helland, J. O., and Hatzignatiou, D. G. 2013: Simulation of three phase capillary pressure curves directly in 2D rock images, paper IPTC 16547 presented at the International Petroleum Technology Conference, Beijing, China, 26-28 March 2013.
Zhou, Y., Helland, J. O., and Hatzignatiou, D. G. 2013: Simulation of three phase capillary pressure curves directly in 2D uniformly-wet rock images.