scholarly journals Analysis of the efficiency of models of transition zones to determine oil-saturation factors and position of contact of hydrocarbons with water

2020 ◽  
pp. 67-76
Author(s):  
G. E. Stroyanetskaya
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Water Saturation ◽  
Residual Water ◽  
Oil Saturation ◽  
Transition Zones ◽  
The Core ◽  
Geophysical Parameter ◽  
Saturation Factor ◽  
Geophysical Information

The article is devoted to the usage of models of transition zones in the interpretation of geological and geophysical information. These models are graphs of the dependences of oil-saturation factors of the collectors on their height above the level with zero capillary pressure, taking into account the geological and geophysical parameter. These models are not recommended for estimating oilsaturation factors of collectors in the transition zone. The height of occurrence of the collector above the level of zero capillary pressure can be estimated from model of the transition zone that take into account the values of the coefficients of residual water saturation factor of the collectors, but only when the model of the transition zone is confirmed by data capillarimetry studies on the core.

Improved Characterization and Modeling of Capillary Transition Zones in Carbonate Reservoirs

2007 ◽  
Vol 10 (02) ◽  
pp. 191-204 ◽  
Author(s):  
Shehadeh K. Masalmeh ◽  
Issa M. Abu-Shiekah ◽  
Xudong Jing
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Relative Permeability ◽  
Dynamic Properties ◽  
Carbonate Reservoirs ◽  
Oil Saturation ◽  
Transition Zones ◽  
Heterogeneous Reservoirs ◽  
Oil Water ◽  
Capillary Pressure Curves

Summary An oil/water capillary transition zone often contains a sizable portion of a field's initial oil in place, especially for those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (Sor) against depth, and on the rock and fluid interactions that control the residual oil saturation (Sor), capillary pressure, and relative permeability characteristics as a function of initial oil saturation. Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the transition zone, modeling both the static and dynamic properties of carbonate fields with large transition zones remains an ongoing challenge. In this paper, we first review the transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed, based on extensive experimental measurements and numerical simulation, for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure curves including hysteresis, based on experimental special-core-analysis (SCAL) data, has a significant impact on the field-performance predictions, especially for heterogeneous reservoirs with transition zones. Introduction The reservoir interval from the oil/water contact (OWC) to a level at which water saturation reaches irreducible is referred to as the capillary transition zone. Fig. 1 illustrates a typical capillary transition zone in a homogeneous reservoir interval within which both the oil and water phases are mobile. The balance of capillary and buoyancy forces controls this so-called capillary transition zone during the primary-drainage process of oil migrating into an initially water-filled reservoir trap. Because the water-filled rock is originally water-wet, a certain threshold pressure must be reached before the capillary pressure in the largest pore can be overcome and the oil can start to enter the pore. Hence, the largest pore throat determines the minimum capillary rise above the free-water level (FWL). As shown schematically in Fig. 2, close to the OWC, the oil/water pressure differential (i.e., capillary pressure) is small; therefore, only the large pores can be filled with oil. As the distance above the OWC increases, an increasing proportion of smaller pores are entered by oil owing to the increasing capillary pressure with height above the FWL. The height of the transition zone and its saturation distribution is determined by the range and distribution of pore sizes within the rock, as well as the interfacial-force and density difference between the two immiscible fluids.

The Method of Characteristics Applied to Oil Displacement by Foam

SPE Journal ◽  
2010 ◽  
Vol 16 (01) ◽  
pp. 8-23 ◽  
Author(s):  
M.. Namdar Zanganeh ◽  
S.I.. I. Kam ◽  
T.C.. C. LaForce ◽  
W.R.. R. Rossen
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Method Of Characteristics ◽  
Water Saturation ◽  
Gas Injection ◽  
Mobility Control ◽  
Residual Water ◽  
Injection Point ◽  
Oil Saturation ◽  
The Method Of Characteristics

Summary Solutions obtained by the method of characteristics (MOC) provide key insights into complex foam enhanced-oil-recovery (EOR) displacements and the simulators that represent them. Most applications of the MOC to foam have excluded oil. We extend the MOC to foam flow with oil, where foam is weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this. We examine SAG (surfactant-alternating-gas) and continuous foam-flood (coinjection of gas and surfactant solution) processes in one dimension, using both the MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large effect on the calculated nature of the displacement. For instance, for gas injection in a SAG process, if foam collapses at the injection point because of infinite capillary pressure, foam has almost no effect on the displacement in the cases examined here. On the other hand, if foam maintains finite strength at the injection point in the gas-injection cycle of a SAG process, displacement leads to implied success in several cases. However, successful mobility control is always possible with continuous foam flood if the initial oil saturation in the reservoir is below the critical oil saturation above which foam collapses. The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the foam quality, the functional forms used to express foam sensitivity to oil and water saturations, and linear and nonlinear relative permeability models.

Coreflood Model Calibration for Alkali Surfactant Polymer Process from a High Salinity Reservoir to Design an ASP Pilot

2021 ◽  
Author(s):  
Marisely Urdaneta
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Water Saturation ◽  
Polymer Concentration ◽  
Chemical Flooding ◽  
Adsorption Parameters ◽  
Oil Saturation ◽  
The Core ◽  
Asp Flooding

Abstract This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.

A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment

SPE Journal ◽  
2020 ◽  
pp. 1-26
Author(s):  
Sajjaat Muhemmed ◽  
Harish Kumar ◽  
Nicklaus Cairns ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Carbon Dioxide ◽  
Water Saturation ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Carbonate Mineral ◽  
Carbonate Minerals ◽  
Oil Saturation ◽  
The Core ◽  
Three Phase ◽  
Water Saturated

Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents’ calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study

Modeling Original Water Saturation in the Transition Zone of a Carbonate Oil Reservoir

2006 ◽  
Vol 9 (06) ◽  
pp. 681-687 ◽  
Author(s):  
Shawket G. Ghedan ◽  
Bertrand M. Thiebot ◽  
Douglas A. Boyd
Keyword(s):  
Simulation Model ◽  
Transition Zone ◽  
Water Saturation ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
High Porosity ◽  
Height Functions ◽  
Transition Zones ◽  
Irreducible Water Saturation ◽  
Original Water

Summary Accurately modeling water-saturation variation in transition zones is important to reservoir simulation for predicting recoverable oil and guiding field-development plans. The large transition zone of a heterogeneous Middle East reservoir was challenging to model. Core-calibrated, log-derived water saturations were used to generate saturation-height-function groups for nine reservoir-rock types. To match the large span of log water saturation (Sw) in the transition zone from the free-water level (FWL) to minimum Sw high in the oil column, three saturation-height functions per rock type (RT) were developed, one each for the low-, medium-, and high-porosity range. Though developed on a different scale from the simulation-model cells, the saturation profiles generated are a good statistical match to the wireline-log-interpreted Sw, and bulk volume of water (BVW) and fluid volumetrics agree with the geological model. RT-guided saturation-height functions proved a good method for modeling water saturation in the simulation model. The technique emphasizes the importance of oil/brine capillary pressures measured under reservoir conditions and of collecting an adequate number of Archie saturation and cementation exponents to reduce uncertainties in well-log interpretation. Introduction The heterogeneous carbonate reservoir in this study is composed of both limestone and dolomite layers frequently separated by non-reservoir anhydrite layers (Ghedan et al. 2002). Because of its heterogeneity, this reservoir, like other carbonate reservoirs, contains long saturation-transition zones of significant sizes. Transition zones are conventionally defined as that part of the reservoir between the FWL and the level at which water saturation reaches a minimum near-constant (irreducible water saturation, Swirr) high in the reservoir (Masalmeh 2000). For the purpose of this paper, however, we define transition zones as those parts of the reservoir between the FWL and the dry-oil limit (DOL), where both water and oil are mobile irrespective of the saturation level. Both water and oil are mobile in the transition zone, while only oil is mobile above the transition zone. By either definition, the oil/water transition zone contains a sizable part of this field's oil in place. Predicting the amount of recoverable oil in a transition zone through simulation depends on (among other things) the distribution of initial oil saturation as a function of depth as well as the mobility of the oil in these zones (Masalmeh 2000). Therefore, the characterization of transition zones in terms of original water and oil distribution has a potentially large effect on reservoir recoverable reserves and, in turn, reservoir economics.

APPLICATION OF RESISTIVITY INVERSION MODELLING TO ENHANCE WATER SATURATION CALCULATIONS FROM WIRELINE LOGS

2000 ◽  
Vol 40 (1) ◽  
pp. 355
Author(s):  
C.J. Shield
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Strong Relationship ◽  
Data Set ◽  
Hydrocarbon Reservoir ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Resistivity Logs ◽  
Resistivity Inversion ◽  
Induction Logs

Water saturation (Sw) values calculated from resistivity or induction logs are often higher than those measured from core-derived capillary pressure (Pc) measurements. The core-derived Sw measurements are commonly applied for reservoir simulation in preference to the log-derived Sw calculations. As it is economically and logistically impractical to core every hydrocarbon reservoir, a method of correlating the core-derived Sw to resistivity/induction logs is required. Two-dimensional resistivity modelling is applied to dual laterolog data to ascertain the applicability of this technique.The Griffin and Scindian/Chinook Fields, offshore Western Australia, have been producing hydrocarbons since 1994 from two early-to-middle Cretaceous reservoirs, the clean quartzose sandstones of the Zeepaard Formation and the overlying glauconitic, quartzose sandstones of the Birdrong Formation. Routine and special core analysis of cores recovered from wells intersecting these two reservoirs creates an excellent data set with which to correlate the good quality wireline log data.A strong relationship is noted between the modelled water saturation from resistivity logs, and the irreducible water saturation measured from core capillary pressure data. Correlation between the core-derived permeability and the invasion diameter calculated from the modelled laterolog data is shown to produce a locally applicable means of estimating permeability from the resistivity modelling results.The evaluation of these data from the Griffin and Scindian/Chinook Fields provides a method for reducing appraisal and development well analysis costs, through the closer integration of core and wireline log data at an earlier stage of the field appraisal phase.

A New Multiphysics Method for Simultaneous Assessment of Permeability and Saturation-Dependent Capillary Pressure in Hydrocarbon-Bearing Rocks

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Artur Posenato Garcia ◽  
Zoya Heidari
Keyword(s):  
Pore Structure ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Water Saturation ◽  
Rock Physics ◽  
Rock Fabric ◽  
The Core ◽  
Directional Permeability ◽  
Water Saturated ◽  
Pore Body

Summary Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) relies on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability still rely on model calibration using core measurements. Furthermore, the assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include developing a new multiphysics workflow to quantify rock-fabric features (e.g., porosity, tortuosity, and effective throat size) from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements; introducing rock-physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure; and validating the reliability of the new workflow in the core-scale domain. To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid-substitution algorithm to estimate the T2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T2 distribution for assessment of porosity, pore-body-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from the interpretation of resistivity measurements. We estimate tortuosity from the interpretation of dielectric-permittivity measurements at 960 MHz by applying the concept of capacitive formation factor. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in the core-scale domain on rock samples at different water-saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. We selected core samples from four different rock types, namely Edwards Yellow Limestone, Lueders Limestone, Berea Sandstone, and Texas Cream Limestone. Finally, because the new workflow relies on fundamental rock-physics principles, permeability and saturation-dependent capillary pressure can be estimated from well logs with minimum calibration efforts, which is another unique contribution of this work.

scholarly journals RESERVOIR FEATURES OF THE UPPER CARBON SEDIMENTS (RUNOVSHCHYNSKA AREA OF THE DNIEPER-DONETS BASIN)

2018 ◽  
pp. 30-37 ◽  
Author(s):  
S. Vyzhva ◽  
V. Onyshchuk ◽  
I. Onyshchuk ◽  
M. Reva ◽  
O. Shabatura
Keyword(s):  
Open Porosity ◽  
Permeability Coefficient ◽  
Water Saturation ◽  
Donets Basin ◽  
Residual Water ◽  
Atmospheric Conditions ◽  
Permeability Coefficients ◽  
Reservoir Conditions ◽  
Porosity Coefficient ◽  
Saturation Factor

The main objective of this article is to highlight the results of investigations of filtration capacity features of sandstones and argillites of the Upper Carbon rocks in Runovshchynska area of The Dnieper-Donets basin. The purpose of the research was to assess the promising rocks as possible hydrocarbon reservoirs. The following reservoir features of rock samples such as the open porosity factor, permeability coefficients and residual water saturation factor have been investigated. The correlation of rock density with their porosity was also studied. The porosity study was carried out in atmospheric and reservoir conditions by gas volumetric method and fluid saturation. The bulk density of dry rock samples varies from 2,122 kg/m3 to 2,615 kg/m3 (average 2318 kg/m3), saturated rocks – from 2265 to 2680 kg/m3 (average 2449 kg/m3), and the specific matrix density – from 2562 to 2786 kg/m3 (average 2650 kg/m3). The open porosity coefficient of the studied rocks, in case they were saturated with the synthetic brine, varies from 0.058 to 0.190 (mean 0.126), but if they were saturated with N2 it varies from 0.066 to 0.203 (mean 0.145). Detailed analysis of reservoir conditions modeling revealed that porosity coefficient varies from 0.038 to 0.175 (mean 0.110). Due to the closure of microcracks under rock loading reduced to reservoir conditions the porosity decreases in comparison with atmospheric conditions, which causes a relative decrease in the porosity coefficient from 4.5% to 13.8% (mean 9.0%) from atmospheric conditions to reservoir conditions. The permeability coefficient of rocks varies from 0.03 fm2 to 240.57 fm2 (mean 11.87 fm2). The residual water saturation factor of rocks varies from 0.02 to 0.89 (mean 0.36). The classification of the reservoir characteristics of the investigated samples by the permeability coefficients and residual water saturation factors has been fulfilled. The correlation analysis has allowed establishing a series of empirical relationships between the reservoir parameters of the studied rocks (density, porosity coefficient, permeability coefficient and residual water saturation factor). The results of complex petrophysical researches indicated that the promising oil-bearing intervals of the horizons G-6, G-7v, G-7n have, in general increased values of reservoir parameters.

Effect of Interfacial Tension on Water/Oil Relative Permeability on the Basis of History Matching to Coreflood Data

2014 ◽  
Vol 17 (01) ◽  
pp. 37-48 ◽  
Author(s):  
Edwin Andrew Chukwudeme ◽  
Ingebret Fjelde ◽  
Kumuduni Abeysinghe ◽  
Arild Lohne
Keyword(s):  
Interfacial Tension ◽  
Relative Permeability ◽  
Capillary Number ◽  
History Matching ◽  
Water Saturation ◽  
Residual Water ◽  
End Effects ◽  
The Core ◽  
Rate Dependent ◽  
Phase Saturation

Summary The effect of interfacial tension (IFT) on the displacement of the nonwetting and wetting phases has been investigated by the use of simulations/history matching of flooding experiments. In surfactant flooding, a conventional assumption is to neglect the effect of capillary pressure (Pc) on measured two-phase properties. The methodology applied in this paper allows improved interpretation of experimental results by correcting for the influence of capillary end effects on the measured capillary desaturation curve (CDC) and on the estimated relative permeability (kr). Three fluid systems of different IFTs were prepared by use of a solvent system (CaCl2 brine/iso-octane/isopropanol) rather than a surfactant system with the assumption that both systems have similar flood behavior at reduced IFT. Three coreflood cycles, including multirate oil injection (drainage) followed by multirate water injection (imbibition), were carried out at each IFT in water-wet Berea cores. The kr functions corrected for capillary end effects were derived by numerically history matching the experimental production and pressure-drop (PD) history. A typical CDC is observed for the nonwetting phase oil, with a roughly constant plateau in residual oil saturation (ROS), Sor, below a critical capillary number (Ncc) and a declining slope above Ncc toward zero Sor. No influence of Pc was found for the nonwetting-phase CDC. The results from the displacement of the wetting phase formed an apparent CDC with a declining slope and no Ncc. Analyzing the wetting-phase results, we find that the wetting-phase CDC is not a true CDC. First, it is a plot of the average remaining water saturation (Sw) in the core which, in all the experiments, is higher than residual water saturation, Swr, obtained from Pc measurements. Second, we find that the remaining Sw is only partly a function of Nc. At low Nc, the water production (WP) is limited by capillary end effects. Rate-dependent WP observed with the high-IFT system is fully reproduced in simulations by use of constant kr and Pc. The remaining wetting-phase saturation at a low capillary number (Nc) is a result of the core-scale balance between viscous and capillary forces and would, for example, depend on the core length. At a higher Nc, the WP is found to be limited by the low kr tail, typical for wetting phases. However, we find that the kr functions become rate dependent at a higher Nc, and we assume that this rate dependency can be modeled as a function of Nc. The remaining wetting-phase saturation at a higher Nc would then be a function of Nc and the number of pore volumes (PVs) injected. The observed Nc dependency in the flow functions indicates a potential for the accelerated production of the wetting phase by use of surfactant. Assuming that the results obtained here for the wetting phase also apply to oil in a mixed-wet system, it is strongly recommended to evaluate the effect of both Pc and Ncc when designing a surfactant model for a mixed-wet field.

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