A Mixed-Wet Hysteretic Relative Permeability and Capillary Pressure Model in a Chemical Compositional Reservoir Simulator

1999 ◽  
Author(s):  
M. Delshad ◽  
R.J. Lenhard ◽  
Mart Oostrom ◽  
G.A. Pope ◽  
S. Yang
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Reservoir Simulator

History Matching Heterogeneous Coreflood of CO2/Brine by Use of Compositional Reservoir Simulator and Geostatistical Approach

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 267-276 ◽  
Author(s):  
Xianhui Kong ◽  
Mojdeh Delshad ◽  
Mary F. Wheeler
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Mean Value ◽  
Heterogeneous Distribution ◽  
Compositional Model ◽  
The Core ◽  
The Mean ◽  
Relative Permeability Curves ◽  
Reservoir Simulator

Summary Numerical modeling and simulation are essential tools for developing a better understanding of the geologic characteristics of aquifers and providing technical support for future carbon dioxide (CO2) storage projects. Modeling CO2 sequestration in underground aquifers requires the implementation of models of multiphase flow and CO2 and brine phase behavior. Capillary pressure and relative permeability need to be consistent with permeability/porosity variations of the rock. It is, therefore, crucial to gain confidence in the numerical models by validating the models and results by use of laboratory and field pilot results. A published CO2/brine laboratory coreflood was selected for our simulation study. The experimental results include subcore porosity and CO2-saturation distributions by means of a computed tomography (CT) scanner along with a CO2-saturation histogram. Data used in this paper are all based on those provided by Krause et al. (2011), with the exception of the CT porosity data. We generated a heterogeneous distribution for the porosity but honoring the mean value provided by Krause et al. (2011). We also generated the permeability distribution with the mean value for the whole core given by Krause et al. (2011). All the other data, such as the core dimensions, injection rate, outlet pressure, temperature, relative permeability, and capillary pressure, are the same as those in Krause et al. (2011). High-resolution coreflood simulations of brine displacement with supercritical CO2 are presented with the compositional reservoir simulator IPARS (Wheeler and Wheeler 1990). A 3D synthetic core model was constructed with permeability and porosity distributions generated by use of the geostatistical software FFTSIM [Jennings et al. (2000)], with cell sizes of 1.27×1.27×6.35 mm. The core was initially saturated with brine. Fluid properties were calibrated with the equation-of-state (EOS) compositional model to match the measured data provided by Krause et al. (2011). We used their measured capillary pressure and relative permeability curves. However, we scaled capillary pressure on the basis of the Leverett J-function (Leverett 1941) for permeability, porosity, and interfacial tension (IFT) in every simulation grid cell. Saturation images provide insight into the role of heterogeneity of CO2 distribution in which a slight variation in porosity gives rise to large variations in CO2-saturation distribution in the core. High-resolution numerical results indicated that accurate representation of capillary pressure at small scales was critical. Residual brine saturation and the subsequent shift in the relative permeability curves showed a significant impact on final CO2 distribution in the core.

Assessment and Inclusion of Capillary Pressure/Relative Permeability Hysteresis Effects in Downhole Water Sink (DWS) Well Technology for Water Coning Control

2001 ◽  
Author(s):  
Solomon O. Inikori ◽  
Andrew K. Wojtanowicz
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Production ◽  
Well Performance ◽  
Water Drainage ◽  
Well Design ◽  
Water Coning ◽  
Capillary Pressures ◽  
Reservoir Simulator ◽  
Downhole Water Sink

Abstract The objective of this study is to assess the effects of capillary pressures and relative permeability hysteresis on the performance of wells using the downhole water sink (DWS) technology for water coning control. In the study a commercial reservoir simulator has been adopted to evaluate well performance under conditions of stabilized oil production/water drainage rates for various combinations of these rates. Operational domain of water-free oil production, Inflow Performance Window (IPW), was used to quantify the effects of capillary pressure transition zone and relative permeability hysteresis on the water coning - control performance of DWS wells. Field data from wells in Canada, West Africa and Louisiana exhibiting severe problems of water coning were used in this study. The simulation results show that the basic concept of the DWS is unchanged by the inclusion of capillary pressure and relative permeability hysteresis. However, these effects may cause considerable reduction in the size of the water-free oil production domain and lead to increase in water production. The results also indicate that, for the same reservoir, converting conventional wells with prior water coning history to DWS application would not be as beneficial as DWS completions on new wells. Thus the effect of drainage-imbibition relative permeability hysteresis should be included in the DWS well design practice.

Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well

SPE Journal ◽  
2012 ◽  
Vol 17 (04) ◽  
pp. 1047-1055 ◽  
Author(s):  
Romain L. Chassagne ◽  
Paul S. Hammond
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Drilling Fluid ◽  
Hysteretic Behavior ◽  
Pore Network Model ◽  
Time Behavior ◽  
Observation Well ◽  
Invaded Zone ◽  
Reservoir Simulator ◽  
Observation Wells

Summary We used a commercial reservoir simulator to study, first, the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure and, second, the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behavior of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account by the use of the Carlson model, with the various bounding drainage and imbibition curves computed from a pore network model. Filtrate invasion into a hydrocarbon formation influences the readings of well-logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behavior of invasion around observation wells where no flow in or out of the formation occurs after completion, and with regard to the influence of formation wettability. We find that after sufficient time, the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil/mixed-wet case. Nonwetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the endpoints of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil/mixed-wet case. The simulation results allow us to understand how logging-tool measurements made in cased observation wells are influenced by drilling-fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and the persistence of invaded zone saturation and between invaded zone saturation and the distortion of subsequent flood fronts.

A Machine Learning Methodology for Rock-Typing Using Relative Permeability Curves

2021 ◽  
Author(s):  
Carlos Esteban Alfonso ◽  
Frédérique Fournier ◽  
Victor Alcobia
Keyword(s):  
Machine Learning ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Fractional Flow ◽  
Flow Curves ◽  
Rock Types ◽  
Rock Typing ◽  
Relative Permeability Curves ◽  
Permeability Data

Abstract The determination of the petrophysical rock-types often lacks the inclusion of measured multiphase flow properties as the relative permeability curves. This is either the consequence of a limited number of SCAL relative permeability experiments, or due to the difficulty of linking the relative permeability characteristics to standard rock-types stemming from porosity, permeability and capillary pressure. However, as soon as the number of relative permeability curves is significant, they can be processed under the machine learning methodology stated by this paper. The process leads to an automatic definition of relative permeability based rock-types, from a precise and objective characterization of the curve shapes, which would not be achieved with a manual process. It improves the characterization of petrophysical rock-types, prior to their use in static and dynamic modeling. The machine learning approach analyzes the shapes of curves for their automatic classification. It develops a pattern recognition process combining the use of principal component analysis with a non-supervised clustering scheme. Before this, the set of relative permeability curves are pre-processed (normalization with the integration of irreducible water and residual oil saturations for the SCAL relative permeability samples from an imbibition experiment) and integrated under fractional flow curves. Fractional flow curves proved to be an effective way to unify the relative permeability of the two fluid phases, in a unique curve that characterizes the specific poral efficiency displacement of this rock sample. The methodology has been tested in a real data set from a carbonate reservoir having a significant number of relative permeability curves available for the study, in addition to capillary pressure, porosity and permeability data. The results evidenced the successful grouping of the relative permeability samples, according to their fractional flow curves, which allowed the classification of the rocks from poor to best displacement efficiency. This demonstrates the feasibility of the machine learning process for defining automatically rock-types from relative permeability data. The fractional flow rock-types were compared to rock-types obtained from capillary pressure analysis. The results indicated a lack of correspondence between the two series of rock-types, which testifies the additional information brought by the relative permeability data in a rock-typing study. Our results also expose the importance of having good quality SCAL experiments, with an accurate characterization of the saturation end-points, which are used for the normalization of the curves, and a consistent sampling for both capillary pressure and relative permeability measurements.

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