Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 152-169 ◽  
Author(s):  
Y.. Zhou ◽  
J. O. Helland ◽  
D. G. Hatzignatiou
Keyword(s):  
Capillary Pressure ◽  
Cross Sections ◽  
Water Saturation ◽  
Gas Oil ◽  
Initial Water ◽  
Three Phase ◽  
Mixed Wettability ◽  
Oil Water ◽  
Simulation Results ◽  
Capillary Pressure Curves

Summary In this study, we present a three-phase, mixed-wet capillary bundle model with cross sections obtained from a segmented 2D rock image, and apply it to simulate gas-invasion processes directly on images of Bentheim sandstone after two-phase saturation histories consisting of primary drainage, wettability alteration, and imbibition. We calculate three-phase capillary pressure curves, corresponding fluid configurations, and saturation paths for the gas-invasion processes and study the effects of mixed wettability and saturation history by varying the initial water saturation after primary drainage and simulating gas invasion from different water saturations after imbibition. In this model, geometrically allowed gas/oil, oil/water, and gas/water interfaces are determined in the pore cross sections by moving two circles in opposite directions along the pore/solid boundary for each of the three fluid pairs separately. These circles form the contact angle with the pore walls at their front arcs. For each fluid pair, circle intersections determine the geometrically allowed interfaces. The physically valid three-phase fluid configurations are determined by combining these interfaces systematically in all permissible ways, and then the three-phase capillary entry pressures for each valid interface combination are calculated consistently on the basis of free-energy minimization. The valid configuration change is given by the displacement with the most favorable (the smallest) gas/oil capillary entry pressure. The simulation results show that three-phase oil/water and gas/oil capillary pressure curves are functions of two saturations at mixed wettability conditions. We also find that oil layers exist in a larger gas/oil capillary pressure range for mixed-wet conditions than for water-wet conditions, even though a nonspreading oil is considered. Simulation results obtained in sandstone rock sample images show that gas-invasion paths may cross each other at mixed-wet conditions. This is possible because the pores have different and highly complex, irregular shapes, in which simultaneous bulk-gas and oil-layer invasion into water-filled pores occur frequently. The initial water saturation at the end of primary drainage has a significant effect on the gas-invasion processes after imbibition. Small initial water saturations yield more-oil-wet behavior, whereas large initial water saturations show more-water-wet behavior. However, in both cases, the three-phase capillary pressure curves must be described by a function of two saturations. For mixed-wet conditions, in which some pores are water-wet and other pores are oil-wet, the gas/oil capillary pressure curves can be grouped into two curve bundles that represent the two wetting states. Finally, the results obtained in this work demonstrate that it is important to describe the pore geometry accurately when computing the three-phase capillary pressure and related saturation paths in mixed-wet rock.

scholarly journals Pore-Scale Modelling of Three-Phase Capillary Pressure Curves Directly in Uniformly Wet Rock Images

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Yingfang Zhou ◽  
Dimitrios Georgios Hatzignatiou ◽  
Johan Olav Helland ◽  
Yulong Zhao ◽  
Jianchao Cai
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Pore Space ◽  
Phase Region ◽  
Gas Oil ◽  
Two Phase ◽  
Sem Image ◽  
Three Phase ◽  
Scale Modelling ◽  
Capillary Pressure Curves

In this work, we developed a semianalytical model to compute three-phase capillary pressure curves and associated fluid configurations for gas invasion in uniformly wet rock images. The fluid configurations and favorable capillary entry pressures are determined based on free energy minimization by combining all physically allowed three-phase arc menisci. The model was first validated against analytical solutions developed in a star-shaped pore space and subsequently employed on an SEM image of Bentheim sandstone. The simulated fluid configurations show similar oil-layer behavior as previously imaged three-phase fluid configurations. The simulated saturation path indicates that the oil-water capillary pressure can be described as a function of the water saturation only. The gas-oil capillary pressure can be represented as a function of gas saturation in the majority part of the three-phase region, while the three-phase displacements slightly reduce the accuracy of such representation. At small oil saturations, the gas-oil capillary pressure depends strongly on two-phase saturations.

A Dimensionless Capillary Pressure Function for Imbibition Derived From Pore-Scale Modeling in Mixed-Wet-Rock Images

SPE Journal ◽  
2012 ◽  
Vol 18 (02) ◽  
pp. 296-308 ◽  
Author(s):  
Y.. Zhou ◽  
J.O.. O. Helland ◽  
D.G.. G. Hatzignatiou
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Wettability Alteration ◽  
Scale Model ◽  
Pore Scale ◽  
Pressure Function ◽  
Initial Water ◽  
Scale Modeling ◽  
Pore Scale Modeling ◽  
Capillary Pressure Curves

Summary It has been demonstrated experimentally that Leverett's J-function yields almost unique dimensionless drainage capillary pressure curves in relatively homogeneous rocks at strongly water-wet conditions, whereas for imbibition at mixed-wet conditions, it does not work satisfactorily because the permeability dependency on capillary pressure has been reported to be weak. The purpose of this study is to formulate a new dimensionless capillary pressure function for mixed-wet conditions on the basis of pore-scale modeling, which could overcome these restrictions. We simulate drainage, wettability alteration, and imbibition in 2D rock images by use of a semianalytical pore-scale model that represents the identified pore spaces as cross sections of straight capillary tubes. The fluid configurations occurring during drainage and imbibition in the highly irregular pore spaces are modeled at any capillary pressure and wetting condition by combining the free-energy minimization with an arc meniscus (AM)-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Capillary pressure curves for imbibition are simulated for different mixed-wet conditions in Bentheim sandstone samples, and the results are scaled by a newly proposed improved J-function that accounts for differences in formation wettability induced by different initial water saturations after primary drainage. At the end of primary drainage, oil-wet-pore wall segments are connected by many water-wet corners and constrictions that remain occupied by water. The novel dimensionless capillary pressure expression accounts for these conditions by introducing an effective contact angle that depends on the initial water saturation and is related to the wetting property measured at the core scale by means of a wettability index. The accuracy of the proposed J-function is tested on 36 imbibition capillary pressure curves for different mixed-wet conditions that are simulated with the semianalytical model in scanning-electron-microscope (SEM) images of Bentheim sandstone. The simulated imbibition capillary pressure curves and the reproduced curves, based on the proposed J-function, are in good agreement for the mixed-wet conditions considered in this study. The detailed behavior is explained by analyzing the fluid displacements occurring in the pore spaces. It is demonstrated that the proposed J-function could be applied to mixed-wet conditions to generate a family of curves describing different wetting states induced by assigning different wetting properties on the solid surfaces or by varying the initial water saturation after primary drainage. The variability of formation wettability and permeability could be described more accurately in reservoir-simulation models by means of the proposed J-function, and hence the opportunity arises for improved evaluation of core-sample laboratory experiments and reservoir performance.

Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery

1999 ◽  
Vol 2 (01) ◽  
pp. 25-36 ◽  
Author(s):  
A.B. Dixit ◽  
S.R. McDougall ◽  
K.S. Sorbie ◽  
J.S. Buckley
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Aging Process ◽  
Water Saturation ◽  
Contact Angles ◽  
Initial Water ◽  
Water Imbibition ◽  
Pore Level ◽  
Capillary Pressure Curves

Summary The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed. Introduction In crude oil/brine/rock (COBR) systems, pore level displacements of oil and brine and hence the corresponding petrophysical flow parameters (e.g., Pc and krw/kro) describing these displacements are governed by the pore geometry, topology and wettability of the system. A number of excellent review papers are available that describe experimental investigations of the effect of wettability on capillary pressure and oil-water relative permeability curves.1–5 In COBR systems, wettability alterations depend upon the mineralogical composition of the rock, pH and/or composition of the brine, crude oil composition, initial water saturation, reservoir temperature, etc.6–12 Therefore, in recent years, interest in restoring the wettability of reservoir core using crude oil and formation brine has greatly increased.3,4,13,14 In this approach, cleaned reservoir core is first saturated with brine and then oil flooded to initial water saturation using crude oil. The core containing crude oil and brine is then aged to alter its wettability state. Wettability measurements, such as Amott and USBM tests, and waterflood experiments are then typically conducted on the aged core. This entire process broadly mimics the actual flow sequences in the reservoir; consequently, the wettability alterations are more realistic than those achieved using chemical treatment methods. During the aging process, wettability may be altered to vastly different degrees depending upon many factors, including those mentioned above. In addition, aging time, thickness of existing water films and wetting film disjoining pressure isotherms also play important roles. Hence, the final wettability state of a re-conditioned core will generally be case specific.

Physically Based Capillary Pressure Correlation for Mixed-Wet Reservoirs From a Bundle-of-Tubes Model

SPE Journal ◽  
2006 ◽  
Vol 11 (02) ◽  
pp. 171-180 ◽  
Author(s):  
Johan Olav Helland ◽  
Svein M. Skjaeveland
Keyword(s):  
Capillary Pressure ◽  
Cross Sections ◽  
Numerical Models ◽  
Contact Angle Hysteresis ◽  
Laboratory Data ◽  
Pore Shape ◽  
Cylindrical Tubes ◽  
Physically Based ◽  
Mixed Wettability ◽  
Capillary Pressure Curves

Summary It is shown that the main characteristics of mixed-wet capillary pressure curves with hysteretic scanning loops can be reproduced by a bundle-of-triangular-tubes model. Accurate expressions for the entry pressures are employed, truly accounting for the mixed wettability and the diverse fluid configurations that arise from contact angle hysteresis and pore shape. The simulated curves are compared with published correlations that have been suggested by inspection of laboratory data from core plug experiments. Introduction Knowledge of the functional relationship between capillary pressure and saturation is required in numerical models to solve the equations for fluid flow in the reservoir. In practice, this relationship is formulated as a capillary pressure correlation with several parameters that usually are to be determined from experimental data. Generally, it is not evident how these parameters should be adjusted to account for variations in physical properties such as wettability, pore shape, pore-size distribution, and the underlying pore-scale processes. Therefore, a more physically based correlation, accounting for observable properties, would improve the reliability of the correlation and extend its applicability range. Analytical correlations may be derived assuming a bundle-of-tubes representation of the pore network. Following this approach for a model of cylindrical tubes, Huang et al. (1997) derived a capillary pressure correlation for primary drainage and the hysteresis bounding loop, accounting for variations in wettability. Princen (1992) computed numerically the relationship between capillary pressure and saturation for primary drainage and imbibition for a bundle of tubes with curved triangular cross sections of uniform wettability. He made no attempt, however, to develop any correlation.

scholarly journals Revisiting the applications of drainage capillary pressure curves in water-wet hydrocarbon systems

2016 ◽  
Vol 8 (1) ◽  
Author(s):  
István Nemes
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Pressure Curve ◽  
Initial Water ◽  
New Approach ◽  
Capillary Pressure Curve ◽  
Side Track ◽  
Relationship Of ◽  
Capillary Pressure Curves ◽  
The Relationship

AbstractThe main focus of the paper is to introduce a new approach at studying and modelling the relationship of initial water saturation profile and capillarity in water-wet hydrocarbon reservoirs, and describe the available measurement methods and possible applications. As a side track it aims to highlight a set of derivable parameters of mercury capillary curves using the Thomeer-method. Since the widely used mercury capillary pressure curves themselves can lead to over-, or underestimations regarding in-place and technical volumes and misinterpreted reservoir behaviour, the need for a proper capillary curve is reasonable. Combining the results of mercury and centrifuge capillary curves could yield a capillary curve preserving the strengths of both methods, while overcoming their weaknesses. Mercury injection capillary curves were normalized by using the irreducible water saturations derived from centrifuge capillary pressure measurements of the same core plug, and this new, combined capillary curve was applied for engineering calculations in order to make comparisons with other approaches. The most significant benefit of this approach is, that all of the measured data needed for a valid drainage capillary pressure curve represents the very same sample piece.

Proxy models for evaluation of permeability, three-phase relative permeability, and capillary pressure curves from rate-transient data

SIMULATION ◽  
2019 ◽  
pp. 003754971985713 ◽  
Author(s):  
Zhenzihao Zhang ◽  
Turgay Ertekin
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Functional Relationship ◽  
Water Saturation ◽  
Petrophysical Properties ◽  
Laboratory Measurements ◽  
Connate Water ◽  
Three Phase ◽  
Transient Data ◽  
Critical Gas Saturation

This study developed a data-driven forecasting tool that predicts petrophysical properties from rate-transient data. Traditional estimations of petrophysical properties, such as relative permeability (RP) and capillary pressure (CP), strongly rely on coring and laboratory measurements. Coring and laboratory measurements are typically conducted only in a small fraction of wells. To contend with this constraint, in this study, we develop artificial neural network (ANN)-based tools that predict the three-phase RP relationship, CP relationship, and formation permeability in the horizontal and vertical directions using the production rate and pressure data for black-oil reservoirs. Petrophysical properties are related to rate-transient data as they govern the fluid flow in oil/gas reservoirs. An ANN has been proven capable of mimicking any functional relationship with a finite number of discontinuities. To generate an ANN representing the functional relationship between rate-transient data and petrophysical properties, an ANN structure pool is first generated and trained. Cases covering a wide spectrum of properties are then generated and put into training. Training of ANNs in the pool and comparisons among their performance yield the desired ANN structure that performs the most effectively among the ANNs in the pool. The developed tool is validated with blind tests and a synthetic field case. Reasonable predictions for the field cases are obtained. Within a fraction of second, the developed ANNs infer accurate characteristics of RP and CP for three phases as well as residual saturation, critical gas saturation, connate water saturation, and horizontal permeability with a small margin of error. The predicted RP and CP relationship can be generated and applied in history matching and reservoir modeling. Moreover, this tool can spare coring expenses and prolonged experiments in most of the field analysis. The developed ANNs predict the characteristics of three-phase RP and CP data, connate water saturation, residual oil saturation, and critical gas saturation using rate-transient data. For cases fulfilling the requirement of the tool, the proposed technique improves reservoir description while reducing expenses and time associated with coring and laboratory experiments at the same time.

Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations

2005 ◽  
Vol 127 (3) ◽  
pp. 240-247 ◽  
Author(s):  
D. Brant Bennion ◽  
F. Brent Thomas
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
The United States ◽  
Gas Production ◽  
Pressure Effects ◽  
Formation Damage ◽  
Low Permeability ◽  
Gas Reservoirs ◽  
Initial Water ◽  
The Impact

Very low in situ permeability gas reservoirs (Kgas<0.1mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

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