Capillary Pressure Hysteresis Research Articles

Diffusion hysteresis in unsaturated porous media: A microfluidic study

In unsaturated flow studies, water saturation is commonly used as the sole descriptor for macroscale flow models. However, this approach often results in hydraulic hysteresis in capillary pressure and relative permeability during drainage and imbibition processes. Furthermore, the effects of these behaviors on solute diffusion remain unclear. To address this knowledge gap, we conducted microfluidic experiments to investigate these hysteresis relationships. We firstly implemented drainage and imbibition processes in the micromodel to establish pore-scale water configurations. Subsequently, we upscaled the capillary pressure and diffusion coefficients to the Representative-Elementary-Volume scale. Our results revealed that, at the same saturation levels, the unsaturated diffusion coefficients during drainage were at least 6.1 % higher than during imbibition, indicating the presence of diffusion hysteresis. We observed that this hysteresis was influenced by capillary number and residual water saturation. An increase in the capillary number reduced diffusion hysteresis, similar to the capillary pressure hysteresis. While a decrease in residual saturation rose diffusion hysteresis. We also proposed a quadratic polynomial model that effectively predicts the diffusion coefficient by incorporating both saturation and capillary pressure. This research emphasizes the importance of historical changes in unsaturated water flow, which hold significant implications for modeling solute transport processes.

Comprehensive parametric study of CO2 sequestration in deep saline aquifers

Carbon dioxide injection in deep saline aquifers is a key method for permanently sequestering anthropogenic CO2. This study employs a reactive transport model to explore mineral precipitation/dissolution and its impact on reservoir properties in deep saline aquifers. We also assess capillary pressure and relative permeability hysteresis on various CO2 trapping mechanisms. Results from this study reveal the significant influence of initial brine composition on mineral precipitation/dissolution. The dissolution and precipitation of minerals have different effects around the wellbores compared to the overall reservoir. Additionally, salt concentration (Ca++ and Mg++) and quartz surface area affect CO2 mineralization, while Na+ impacts halite precipitation, altering reservoir flow properties. The effect of capillary pressure is significant, as including the capillary pressure in the simulation case resulted in significantly improved CO2 trapping, achieving almost total dissolution of the injected CO2 in around 300 years. This study offers novel insights into the interactions of reservoir minerals, brine properties, and the injected CO2.

Trapping, hysteresis and Ostwald ripening in hydrogen storage: A pore-scale imaging study

Green hydrogen, produced from surplus electricity during peak production, can be injected into subsurface reservoirs and retrieved during high-demand periods. In this study, X-ray tomography was employed to examine hysteresis resulting from repeated hydrogen injection and withdrawal. An unsteady state experiment was performed to evaluate the distribution of hydrogen and brine after drainage and imbibition cycles: images of the pore-space configuration of fluids were taken immediately once injection had stopped and after waiting for a period of 16 h with no flow. A Bentheimer sandstone sample with a length of 60 mm and diameter of 12.8 mm was used, and hydrogen was injected at ambient temperature and a pore pressure of 1 MPa. The gas flow rate was decreased from 2 ml/min to 0.08 ml/min over three cycles of gas injection followed by water flooding, while the brine injection rate was kept constant. The results showed the presence of capillary pressure hysteresis and hydrogen migration through Ostwald ripening due to the diffusion of gas dissolved in the brine. These phenomena were characterized through analysis of interfacial curvature, area, connectivity and pore occupancy. The hydrogen tended to reside in the larger pore spaces, consistent with water-wet conditions. 16 h after flow had stopped, the hydrogen aggregated into larger ganglia with a single large connected ganglion dominating the volume. Moreover, the Euler characteristic decreased after 16 h, indicating an improvement in connectivity. The work implies that Ostwald ripening – mass transport of dissolved gas – leads to less hysteresis and better connectivity than would be assumed ignoring this effect, as done in assessments of hydrocarbon flow and trapping.

Impact of capillary pressure hysteresis and injection-withdrawal schemes on performance of underground hydrogen storage

HypothesisUnderground hydrogen storage in depleted hydrocarbon reservoirs and aquifers has been proposed as a potential long-term solution to storing intermittently produced renewable electricity, as the subsurface formations provide secure and large storage space. Various phenomena can lead to hydrogen loss in subsurface systems with the key cause being the trapping especially during the withdrawal cycle. Capillary trapping, in particular, is strongly related to the hysteresis phenomena observed in the capillary pressure/saturation and relative-permeability/saturation curves. This paper address two key points: (1) the sole impact of hysteresis in capillary pressure on hydrogen trapping during withdrawal cycles and (2) the dependency of optimal operational parameters (injection/withdrawal flow rate) and the reservoir characteristics, such as permeability, thickness and wettability of the porous medium, on the remaining hydrogen saturation. ModelTo study the capillary hysteresis during underground hydrogen storage, Killough [1] model was implemented in the MRST toolbox [2]. A comparative study was performed to quantify the impact of changes in capillary pressure behaviour by including and excluding the hysteresis and scanning curves. Additionally, this study investigates the impact of injection/withdrawal rates and the aquifer permeability for various capillary and Bond numbers in a homogeneous system. FindingsIt was found that although the hydrogen storage efficiency is not considerably impacted by the inclusion of the capillary-pressure scanning curves, the impact of capillary pressure on the well properties (withdrawal rate and pressure) can become significant. Higher injection and withdrawal rates does not necessarily lead to a better performance in terms of productivity. The productivity enhancement depends on the competition between gravitational, capillary and viscous forces. The observed water upconing at relatively high capillary numbers resulted in low hydrogen productivity. highlighting the importance of well design and placement.

Influence of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability

This study examines the effect of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability. We perform drainage and imbibition injections into a Berea sandstone core and a sintered glass core. The cores receive three injection stages: water, then water-saturated CO2 representing drainage, and finally CO2-saturated water representing imbibition. Pressure difference and fluid production are recorded. To generate relative permeability using these data, we propose that the conventional Johnson–Bossler–Naumann (JBN) method be modified to incorporate capillary pressure boundary conditions. We then compare the results yielded by the JBN and modified-JBN methods, which generate relative permeability for post-breakthrough water saturation. To generate relative permeability for all states of saturation, history matching is used, in which the relative permeability of a numerical model is tuned until the simulated data match the experimental data.For drainage, history-matched relative permeability curves are found to be significantly closer to modified-JBN estimates than to JBN estimates. This indicates that the proposed modified-JBN method can provide a more accurate initial guess for history matching. In addition, using the initial guess generated by modified-JBN is found to reduce the chance of non-unique history-matched relative permeability curves.For imbibition, the CO2-water relative permeability curve is generated directly from history matching because the experimental data are too sparse to apply the JBN or modified-JBN method. Both CO2 and water imbibition relative permeability are found to differ from the drainage relative permeabilities. This so-called relative permeability hysteresis is attributed to contact angle hysteresis. In addition, imbibition CO2-water relative permeability is found to be sensitive to imbibition capillary pressure boundary conditions.

The impact of heterogeneity on the capillary trapping of [formula omitted] in the Captain Sandstone.

A significant uncertainty which remains for CO2 sequestration, is the effect of natural geological heterogeneities and hysteresis on capillary trapping over different length scales. This paper uses laboratory data measured in cores from the Goldeneye formation of the Captain D Sandstone, North Sea in 1D numerical simulations to evaluate the potential capillary trapping from natural rock heterogeneities across a range of scales, from cm to 65m. The impact of different geological realisations, as well as uncertainty in petrophysical properties, on the amount of capillary heterogeneity trapping is estimated. In addition, the validity of upscaling trapping characteristics in terms of the Land trapping parameter is assessed. The numerical models show that the capillary heterogeneity trapped CO2 saturation may vary between 0 and 14% of the total trapped saturation, depending upon the geological realisation and petrophysical uncertainty. When upscaling the Land model from core-scale experimental data, using the maximum experimental Land trapping parameter could increase the expected heterogeneity trapping by a factor of 3. Conversely, depending on the form of the imbibition capillary pressure curve used in the numerical model, including capillary pressure hysteresis may reduce the heterogeneity trapping by up to 70%.

A Thermodynamic Analysis of the Impact of Temperature on the Capillary Pressure in Porous Media

AbstractA thermodynamic analysis of the capillary drainage, imbibition and hysteresis pressure in two‐phase porous media systems at different temperatures has been performed. Expressions for the work required or gained when the fluid saturations change, proportional to the capillary pressures, are presented. The expressions are determined using the criterion that changes in Helmholtz free energy equals zero at equilibrium. From these expressions, the variation of capillary drainage, imbibition and hysteresis pressures for increasing temperature are determined without calculating the actual capillary pressure values. The temperature dependency results show that the capillary drainage pressure declines with a fractional rate for increasing temperature with contribution from two terms, the air‐water interfacial tension and the entropy term, which give a total fractional reduction of −0.0082 K−1, close to the value −0.0084 K−1 found experimentally. The capillary imbibition pressure increases with a total fractional rate versus temperature equal +0.004 K−1 in line with the observation that water tables in soils are lifted upon day‐time heating. The total fractional temperature variation of the hysteresis capillary pressure term declines with a rate of −0.0143 K−1 for increasing temperature in qualitative agreement with experimental data. The results support the hypothesis that the thermodynamic approach applied under given assumptions can account for the major effects determining the temperature dependency of two‐phase capillary pressure in porous media. Furthermore, the entropy term adds an additional hysteresis term to the conventional term, even under isothermal conditions. The capillary pressure hysteresis phenomenon is therefore caused by two effects: Differences in interfacial areas including contact angle hysteresis plus the entropic contribution.

State-of-the-art on capillary pressure hysteresis: Productive techniques for better reservoir performance

Hysteresis has a significant role in evaluating hydrocarbon recovery and better understanding fluid flow in porous media. In this paper, a comprehensive review of research on the hysteresis of capillary pressure ( P c ) and its applications in petroleum engineering are reported. Both theoretical and experimental investigations of hysteresis of P c is compared and discussed in detail. The review highlights a range of concepts in existing models and experimental processes for hysteresis of P c in porous media. Furthermore, this paper tracks the current development of hysteresis and provides insight into future research trends. This study also serves to provide an insight into future research opportunities to fill the research gaps on capillary pressure in the system of porous media.

CO2 geological sequestration in multiscale heterogeneous aquifers: Effects of heterogeneity, connectivity, impurity, and hysteresis

Fundamental understanding of processes controlling geological carbon sequestration (GCS) requires flow and transport modeling in well-characterized aquifer sedimentary deposits. We use three-dimensional, heterogeneous models based on new field studies which incorporate the most important aspects of multiscale architecture in fluvial aquifers. In addition, we use the associated facies-dependent constitutive relations for both relative permeability and capillary pressure curves and their hysteresis. The novelty of this work is to evaluate how CO2 fate and transport is controlled by (1) the spatial organization, volume proportions, and connectivity of sedimentary facies types, (2) facies-dependent constitutive relations and their hysteretic behavior, and (3) presence and/or absence of dissolved components such as methane (CH4) in brine. Model results suggest that the amounts of snap-off and solubility trapping are enhanced by increasing the volume proportion and degree of connectivity of high-permeability facies types. Results also demonstrate that ignoring relative permeability hysteresis leads to underestimation of snap-off trapping and overestimation of solubility trapping. In contrast, neglecting capillary pressure hysteresis (i.e., non-hysteretic Pc) results in overestimation of snap-off trapping and underestimation of solubility trapping. If capillary pressure is totally neglected (i.e., Pc = 0), the amount of trapped CO2 by snap-off and dissolution are, respectively, overestimated and underestimated. Competitive CO2 and CH4 dissolution in brine results in exsolution of CH4 from the aqueous phase into the gaseous phase. Facies connectivity and constitutive relations are also critical for the transport of exsolved CH4. However, disregarding dissolved CH4 leads to overestimation of CO2 trapping capacities.

Hysteresis of output voltage and liquid water transport in gas diffusion layer of polymer electrolyte fuel cells

The hysteresis of PEM fuel cell output voltage of the single cell and multi-cell stack is presented by experiments, during which the in-situ liquid water visualization at certain point of gas channel, quantitative measurement of the RH (relative humidity) and HFR (high frequency resistance) by EIS (electrochemical impedance spectroscopy) were carried out. It is found that HFR makes little contribution to the hysteresis of voltage. Instead, the hysteresis of liquid water saturation s in GDL is believed to dominant this process. Although the hysteresis of capillary pressure of liquid water in GDL has already been the presented in previous works, it is for the first time that a simplified one-dimensional model on liquid water saturation is updated considering this effect to understand the possible relation between them. Two different liquid water saturation s distributions during imbibition and drainage are obtained by simulation and related hypothesis of different water morphology in GDL is proposed. Furthermore, according to the simulation results, the GDL consisting of material with high resistance to water penetrating is found to have the better performance in the flooding condition, but weak capability to maintain residual water during drainage of PEM fuel cell.

Potential CO2 and brine leakage through wellbore pathways for geologic CO2 sequestration using the National Risk Assessment Partnership tools: Application to the Big Sky Regional Partnership

Geologic CO2 sequestration (GCS) has received high-level attention from the global scientific community as a response to climate change due to higher concentrations of CO2 in the atmosphere. However, GCS in saline aquifers poses certain risks including CO2/brine leakage through wells or non-sealing faults into groundwater or to the earth’s surface. Understanding crucial reservoir parameters and other geologic features affecting the likelihood of these leakage occurrences will aid the decision-making process regarding GCS operations. In this study, we develop a science-based methodology for quantifying risk profiles at geologic CO2 sequestration sites as part of US DOE’s National Risk Assessment Partnership (NRAP). We apply NRAP tools to a field scale project in a fractured saline aquifer located at Kevin Dome, Montana, which is part of DOE’s Big Sky Carbon Sequestration Partnership project. Risks associated with GCS injection and monitoring are difficult to quantify due to a dearth of data and uncertainties. One solution is running a large number of numerical simulations of the primary CO2 injection reservoir, shallow reservoirs/aquifers, faults, and wells to address leakage risks and uncertainties. However, a full-physics simulation is not computationally feasible because the model is too large and requires fine spatial and temporal discretization to accurately reproduce complex multiphase flow processes. We employ the NRAP Integrated Assessment Model (NRAP-IAM), a hybrid system model developed by the US-DOE for use in performance and quantitative risk assessment of CO2 sequestration. The IAM model requires reduced order models (ROMs) developed from numerical reservoir simulations of a primary CO2 injection reservoir. The ROMs are linked with discrete components of the NRAP-IAM including shallow reservoirs/aquifers and the atmosphere through potential leakage pathways. A powerful stochastic framework allows NRAP-IAM to be used to explore complex interactions among a large number of uncertain variables and to help evaluate the likely performance of potential sequestration sites. Using the NRAP-IAM, we find that the potential amount of CO2 leakage is most sensitive to values of permeability, end-point CO2 relative permeability, hysteresis of CO2 relative permeability, capillary pressure, and permeability of confining rocks. In addition to demonstrating the application of the NRAP risk assessment tools, this work shows that GCS in the Kevin Dome has a higher probability of encountering injectivity limitations during injection of CO2 into the Middle Duperow formation than previous studies have calculated. Finally, we estimate very low risk of CO2 leakage to the atmosphere unless the quality of the legacy well completions is extremely poor.

Microscopic theory of capillary pressure hysteresis based on pore-space accessivity and radius-resolved saturation

Continuum models of porous media use macroscopic parameters and state variables to capture essential features of pore-scale physics. We propose a macroscopic property “accessivity” (α) to characterize the network connectivity of different sized pores in a porous medium, and macroscopic state descriptors “radius-resolved saturations” (ψw(F),ψn(F)) to characterize the distribution of fluid phases within. Small accessivity (α→0) implies serial connections between different sized pores, while large accessivity (α→1) corresponds to more parallel arrangements, as the classical capillary bundle model implicitly assumes. Based on these concepts, we develop a statistical theory for quasistatic immiscible drainage-imbibition in arbitrary cycles, and arrive at simple algebraic formulae for updating ψnF that naturally capture capillary pressure hysteresis, with α controlling the amount of hysteresis. These concepts may be used to interpret hysteretic data, upscale pore-scale observations, and formulate new constitutive laws by providing a simple conceptual framework for quantifying connectivity effects, and may have broader utility in continuum modeling of transport, reactions, and phase transformations in porous media.

Trapping of buoyancy-driven CO2 during imbibition

This paper presents a simulation study on the influence of rock heterogeneity on the distribution and magnitude of trapped CO2 resulting from a drainage/imbibition sequence in a saline aquifer with buoyant CO2. Four scenarios are studied, three simple 1D cases and a 2D case with heterogeneity derived from realistic architecture inspired by tidal sand deposits, having combined layering and crossbedding and sediment property contrasts. The four cases are examined in order to understand which underlying mechanisms are responsible for the results observed and therefore also which processes it is necessary to reflect in the simulation procedure. It is shown that it is important to take into account hysteresis in the capillary pressure. During the imbibition the capillary pressure decreases and the ability to capillary trap the CO2 is reduced and it may in some cases completely vanish. Thus, the capillary pressure hysteresis has a major impact on the amount of trapped CO2. If the imbibition curve has a threshold pressure the sealing power of the barrier is not completely lost, which leads to hyper-trapping, characterised by mobile CO2 being trapped with above end-point saturations. If the imbibition capillary pressure reaches zero, only local barriers constituting effective seals are able to trap free and potentially mobile CO2 and the trapping mechanism is exactly the same as the one acting beneath the top seal. The neglection of capillary pressure hysteresis may result in a large overestimation of the amount of trapped CO2.

The Role of Capillary Hysteresis and Pore‐Scale Heterogeneity in Limiting the Migration of Buoyant Immiscible Fluids in Porous Media

AbstractUnderstanding the main mechanisms affecting long‐term migration and redistribution of injected CO2 in geological carbon storage is needed for developing predictive models to assess environmental risks and designing monitoring schemes. Preparation of a postinjection site care plan is required for CO2 injection wells, including monitoring of pressure changes and injected CO2 plume. Knowledge gaps exist regarding assessment of postinjection monitoring timeframes for the CO2 plume because the processes driving long‐term CO2 plume migration and trapping are not fully understood. In the postinjection stage of geological carbon storage, redistribution of CO2 occurs mainly due to buoyancy and capillary forces. This work presents experimental and modeling studies to investigate processes contributing to postinjection plume distribution and stabilization. We conducted a flow cell experiments (0.5 m × 0.05 m × 0.01 m) with two immiscible fluid phases in a glass bead porous medium to study postinjection plume behavior. We employed a hysteretic macroscopic two‐phase flow model to interpret the experimental results and to understand main processes leading to plume stabilization. Our findings show that capillary pressure hysteresis explains the experimentally observed plume shape and redistribution at early postinjection stages; however, the long‐term plume migration and eventual plume stabilization can only be represented when in addition microscale heterogeneity is accounted for. Results also show that plume stabilization can be extremely slow and that the migration of the plume front can occur through multiple intermittent bursts over long times. Further studies are needed to understand implications of the results for more realistic porous media and large‐scale storage reservoirs.

Cyclic Steam Stimulation Results in High Water Retention for Kuwaiti Heavy-Oil Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184154, “High Water Retention in Cyclic-Steam-Stimulation Wells of Kuwait Heavy-Oil Field,” by Anil Kumar Jain, Amal Al-Sane, and Fatma Ahmad, Kuwait Oil Company, prepared for the 2016 SPE International Heavy Oil Conference and Exhibition, Mangaf, Kuwait, 6–8 December. The paper has not been peer reviewed. Cyclic steam stimulation (CSS) is one of the principal enhanced-oil-recovery methods for heavy oil. CSS was performed in some of the wells of a heavy-oil field in Kuwait. Multiple cycles were applied in these wells. However, the total water produced in each cycle was much less than expected. This paper presents experiments that were conducted to find possible reasons for the high water retention. Hysteresis in CSS Hysteresis in drainage and imbibition nonwetting-phase capillary pressure and relative permeability curves is an established phenomenon. Hysteresis of capillary pressure and relative permeability to water has a great effect on heavy-oil recovery and producing water/oil ratios (WORs) during cyclic steam stimulation. Produced WOR calculated without considering hysteresis will be unrealistically high relative to that observed in the fields. Water Retention During water injection, relative permeability to water increases, and, during the production phase, it decreases; however, it does not follow the same path. Relative permeability to water during the production phase is always less than that during the injection phase at the same water saturation. Irreducible water saturation during the production phase is more than the initial water saturation before injection. The difference between these two water saturations is water retention. The same phenomenon occurs when CSS is applied. As a result of hysteresis and temperature, irreducible water saturation does not reach the initial water saturation. When steam is injected into a formation, the formation becomes increasingly water-wet. In subsequent cycles, steam injection reduces the oil saturation and increases the water saturation around the wellbore. Relative permeability to oil at high water saturation is also reduced. In later cycles, increasingly more water is produced than oil, and, therefore, the WOR increases. The produced water consists of both the condensed steam and the formation water. After steam is injected, fresh water is produced first, and slowly the salinity of the produced water increases. Initially, some of the condensed steam returns, but, later, formation water is produced with the condensed steam. If the well produces for long enough, eventually only formation water will be produced.

Symmetric wetting heterogeneity suppresses fluid displacement hysteresis in granular piles

We investigate experimentally the impact of heterogeneity on the capillary pressure hysteresis in fluid invasion of model porous media. We focus on `symmetric' heterogeneity, where the contact angles the fluid interface makes with the oil-wet ($\theta_1$) and the water-wet ($\theta_2$) beads add up to $\pi$. While enhanced heterogeneity is usually known to increase hysteresis phenomena, we find that hysteresis is greatly reduced when heterogeneities in wettability are introduced. On the contrary, geometric heterogeneity (like bi-disperse particle size) does not lead to such effect. We provide a qualitative explanation of this surprising result, resting on rather general geometric arguments.

Capillary pressure heterogeneity and hysteresis for the supercritical CO2/water system in a sandstone

We report results from an experimental investigation on the hysteretic behaviour of the capillary pressure curve for the supercritical CO2-water system in a Berea Sandstone core. Previous observations have highlighted the importance of subcore-scale capillary heterogeneity in developing local saturations during drainage; we show in this study that the same is true for the imbibition process. Spatially distributed drainage and imbibition scanning curves were obtained for mm-scale subsets of the rock sample non-invasively using X-ray CT imagery. Core- and subcore-scale measurements are well described using the Brooks–Corey formalism, which uses a linear trapping model to compute mobile saturations during imbibition. Capillary scaling yields two separate universal drainage and imbibition curves that are representative of the full subcore-scale data set. This enables accurate parameterisation of rock properties at the subcore-scale in terms of capillary scaling factors and permeability, which in turn serve as effective indicators of heterogeneity at the same scale even when hysteresis is a factor. As such, the proposed core-analysis workflow is quite general and provides the required information to populate numerical models that can be used to extend core-flooding experiments to conditions prevalent in the subsurface, which would be otherwise not attainable in the laboratory.

Effects of low-salinity waterflooding on capillary pressure hysteresis

In this study, low-salinity waterflooding enhanced-oil recovery mechanisms linked to the water–crude oil interfacial viscoelastic response are investigated considering a distinct interfacial effect, namely the water-crude oil interfacial viscoelasticity response. In contrast, wettability alteration is interpreted through analysis of capillary hysteresis. A capillary pressure experimental setup used in our previous research, is utilized here to capture capillary hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method have been implemented to accelerate measurements. The dynamic-static method, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short (<1″ long) core samples, was found to capture the correct envelopes of the capillary pressure curves in a much shorter time span. Two pairs of experiments were conducted to investigate the interfacial visco-elasticity and wettability alteration effects on capillary hysteresis. One pair is conducted on Minnelusa formation rock samples and diluted TC crude oil at 30°C and without any significant aging to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. Results show that low-salinity brine can still increase oil recovery even in the absence of wettability alteration. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. Two additional experiment pairs were conducted on Berea and TC oil at high temperature (70°C). Two cores were subject to the same experimental conditions except that one was allowed to age with crude oil for 3weeks. This aging process was found to render the rock more oil wet, resulting in more pronounced capillary hysteresis and less oil recovery. Our study shows effects of two mechanisms, i.e. fluid–fluid interfacial visco-elasticity and wettability alteration, separately. The interpretation of our unique capillary pressure datasets sheds light on low-salinity waterflooding mechanisms.

A Numerical Study of Two-Phase Flow Models with Dynamic Capillary Pressure and Hysteresis

Saturation overshoot and pressure overshoot are studied by incorporating dynamic capillary pressure, capillary pressure hysteresis and hysteretic dynamic coefficient with a traditional fractional flow equation in one-dimensional space. Using the method of lines, the discretizations are constructed by applying the Castillo–Grone’s mimetic operators in the space direction and a semi-implicit integrator in the time direction. Convergence tests and conservation properties of the schemes are presented. Computed profiles capture both the saturation overshoot and pressure overshoot phenomena. Comparisons between numerical results and experiments illustrate the effectiveness and different features of the models.

Analysis of capillary pressure and relative permeability hysteresis under low-salinity waterflooding conditions

In this work, we analyze measurements of drainage, spontaneous imbibition and forced imbibition capillary pressure curves in conjunction with two-electrode resistivity on sandstone core samples under low- and high-salinity waterflooding conditions. State-of-the-art laboratory equipment able to work with actual reservoir fluids at reservoir conditions was designed and built to conduct these measurements. Unsteady-state coreflooding experiments under similar experimental conditions to those in the capillary pressure tests were also carried out. A black-oil reservoir simulation model was set up to history match experimental production and pressure data to obtain multi-phase flow functions. Two experiments were conducted on Minnelusa formation (eolian sand) rock samples at 93°C with TC crude oil and synthetic brines. Placement of an oil-wet membrane on one plug end and a water-wet disk on the other end guaranteed that only one phase was able to flow through each sample end at any given time. In one experiment, a 57,491ppm-brine (High-Salinity) was used during the imbibition process, while a 20-fold dilution of the High-Salinity brine (Low-Salinity) was used in the other experiment. Correspondingly, two unsteady-state experiments at fixed injection rate were completed on Minnelusa formation rock samples placed in the coreflooding system using comparable experimental conditions as those in the capillary pressure experiments. Comparison of high- and low-salinity experimental results shows that more noticeable capillary hysteresis toward water-wetness arose in the low-salinity experiment. High-salinity experiment results showed that the imbibition resistivity index was higher than that corresponding to drainage. History matching of the transient production data in capillary pressure experiments along with end-points obtained from unsteady-state core flooding experiments was used to obtain relative permeability curves. Availability of high-quality capillary pressure data at reservoir conditions improved the accuracy of relative permeability curves obtained from history matching unsteady-state core flooding experiments. Our results show a substantial improvement in obtaining both capillary pressure and relative permeability curves at reservoir conditions resulting from a combination of steady- and unsteady-state experiments. Capillary pressure results confirm that hysteresis is more prominent under low-salinity conditions and apparent higher oil trapping is observed during imbibition, compared to high-salinity conditions. Unsteady-state coreflooding results also show that low-salinity brine is not conducive to enhanced oil recovery in low-salinity waterflooding. Geochemical effects appear to negatively impact beneficial interfacial mechanisms proposed to benefit oil recovery such as the formation of more viscoelastic interfaces under low-salinity conditions. We conclude that coupling of fluid–fluid and rock–fluid interactions, including geochemical reactions, needs to be accounted for to better explain low-salinity waterflooding mechanisms.