Relative Permeability Hysteresis Research Articles

Steady-state Two-phase Relative Permeability Measurements in Proppant-packed Rough-walled Fractures

Understanding multiphase flow in fractures filled with minerals and proppants is vital in various subsurface applications. Limited experimental data have led to reliance on correlations lacking physical basis. We conducted experiments to characterize relative permeability in rough-walled fractures packed with unconsolidated porous media. We tested fractures packed with water-wet 40/70 sand (silica) and surface-coated ceramic proppants. Brine and mineral oil were used as the wetting and non-wetting fluid phases, respectively. Steady-state (SS) drainage (non-wetting-phase displacing wetting-phase) and imbibition (wetting-phase displacing non-wetting-phase) tests were performed under a wide range of saturation histories (full-cycle and scanning-curves) to study relative permeability hysteresis of the propped fractures. Every SS drainage or imbibition test consisted of several discrete points at which fluid saturations and the corresponding relative permeability were measured by varying the fractional flow rates of fluids whilst maintaining a constant total flow rate. We analyzed residual non-wetting phase saturations and relative permeability trends to understand two-phase flow behavior in each proppant pack. High-resolution x-ray microtomography was used to understand the pore-scale topology, wettability, and to provide insights about the pore-scale displacement mechanisms involved in this study. The results showed that commonly used models to estimate relative permeabilities of fractures significantly overestimated the SS brine and oil relative permeabilities (denoted as krw and kro) measured in this study. Further analysis unveiled that the kro values during imbibition exceeded their drainage counterparts in both proppants, the ceramic proppant exhibited a lower initial water saturation and a higher end-point kro permeability at the end of the drainage displacement, as well as higher krw across all flooding processes. Updated fitting parameters for a Brooks-Corey-type relative permeability correlation are introduced. This study presents improved insights, extensive experimentally generated relative permeability data, and an updated relative permeability correlation, which can be collectively utilized to reduce uncertainties associated with continuum-scale forecasts of multiphase flow behavior in fractured subsurface formations.

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.

A study of non-equilibrium wave groups in two-phase flow in high-contrast porous media with relative permeability hysteresis

Non-equilibrium models are applicable in various physical situations, including phase transitions, hysteresis, and chemical reactions, among others. To model the dynamics of such phenomena, partial differential equations are employed with source terms, as seen in Eq. (1.1). This work focuses on situations where we connect states in equilibrium while allowing for non-equilibrium times. In our model, we model non-equilibrium through relaxation. The source term, in this case, acts as an attractor, and the model’s dynamics allow only a small-time far from equilibrium. We use this theory to model a two-equation system in a two-phase fluid in porous media, where different permeabilities of the flow lead to hysteresis phenomena. We show several examples and study the Riemann solution to gain a better understanding of the solution. We investigate the interplay between nonlinear wave groups of water–oil saturation with different permeabilities in the non-wetting phase and the high-contrast heterogeneity of the porous medium in two-space dimensions. This phenomenon is described by a coupled set of time-dependent partial differential equations of hyperbolic–parabolic–elliptic mixed type. We present and discuss a new projection method with relaxation to obtain 1D-analytical Riemann solutions in an idealized homogenized medium, and we use this solution to validate our numerical method. The primary components of obtaining these solutions are shocks, rarefactions, and bifurcations. We obtain 2D-numerical solutions using an operator splitting approach based on physics, highlighting the discretization methods used. We provide robust analytical–numerical examples to verify the theory and illustrate the approach’s capabilities. In particular, we discuss the 1D-2D behavior of wave groups in situations driven by water–oil infiltration problems of permeable reservoir rocks.

Direct measurement of hydrogen relative permeability hysteresis for underground hydrogen storage

Underground Hydrogen Storage (UHS) is a long-term storage solution which utilises hydrogen as an energy carrier to store large-scale excess renewable energy in the subsurface. Key petrophysical properties, such as wettability and interfacial tension of hydrogen and water have been discovered which provide a practical basis for simulation models. Our work directly measures relative permeability hysteresis during co-injection core floods of hydrogen and water with a capillary number of Nc=2.92×10−7. Segmented micro-CT images are used to determine saturation in the Bentheimer sandstone. Our results demonstrate that hydrogen relative permeability in sandstones is very low, with an end-point relative permeability of krg0=0.049 at Swi= 0.24. Capillary trapping results in residual gas saturation of Sgr= 0.4. Wettability analysis confirms the system is water-wet, with contact angles of 57° at Sgr and 44° at Swi. These results improve the reliability of numerical simulations and demonstrate the possible challenges involved with the commercial application of UHS.

Numerical study of the efficiency of underground hydrogen storage in deep saline aquifers, rock springs uplift, Wyoming

Underground hydrogen storage (UHS) is able to store a large amount of energy with efficiency, thus meeting the high demand for energy in winter. This study aims at investigating the feasibility and efficiency of UHS in the Nugget Sandstone, Rock Springs Uplift, Wyoming. The representative geological model is first constructed with the control of well logs and seismic data. Then the multiphase flow functions are well coupled into the subsurface reservoir model. Following that, based on the uncertainty of reservoir parameters, gas source accessibility, and production cost, the effects of key parameters on H2 fate within the reservoir and H2 recovery efficiency are researched. Simulation outcomes reveal that H2 dissolution into formation brine gives rise to a lower amount of trapped H2 within the reservoir but the recovery ratio is reduced by the H2 dissolution at the end. Relative permeability hysteresis can not only relieve the H2 vertical migration, but also give a wider H2 radial distribution. As the cycle proceeds, relative permeability hysteresis results in the notable enhancement in the trapped H2, leading to a reduction of the final recovery ratio from 0.86 to 0.76 when the residual gas saturation, Sgmax, ranges from 0.2 to 0.4. A slower cushion gas (CG) injection rate gives rise to a smaller final trapped H2, which accordingly results in an increase of recovery ratio. Further, the final recovery ratio changes from 0.835 to 0.846 due to an increase in working gas components from H2:CH4 = 1:1 to H2:CH4 = 3:1. The insights obtained in this study shed a light on accelerating the achievements of decarbonisation goals through the commercial-scale energy conversion and transition from conventional fossil energy and renewable energy to hydrogen.

Mechanistic evaluation of the reservoir engineering performance for the underground hydrogen storage in a deep North Sea aquifer

Underground hydrogen storage (UHS) in aquifers, salt caverns and depleted hydrocarbon reservoirs allows for the storage of larger volumes of H2 compared to surface storage in vessels. In this work, we investigate the impact of aquifer-related mechanisms and parameters on the performance of UHS in an associated North Sea aquifer using 3D numerical compositional simulations.Simulation results revealed that the aquifer's permeability heterogeneity has a significant impact on the H2 recovery efficiency where a more homogenous rock would lead to improved H2 productivity. The inclusion of relative permeability hysteresis resulted in a drop in the H2 injectivity and recovery due to H2 discontinuity inside the aquifer which leads to residual H2 during the withdrawal periods. In contrast, the effects of hydrogen solubility and hydrogen diffusion were negligible when studied each in isolation from other factors. Hence, it is essential to properly account for hysteresis and heterogeneity when evaluating UHS in aquifers.

The Impact of Relative Permeability Hysteresis on CO2 Sequestration in Saline Aquifer

This work analyzed the amount of capillary-trapped CO2 for maximum residual gas saturation due to relative permeability hysteresis. Upward migration of CO2 is unwanted because it increases the risk of CO2 migration from storage sites to the surface. One way to mitigate CO2 leakage risk is to reduce the vertical CO2 migration to improved storage capacity and containment security. A compositional simulator (CMG-GEM) was used to simulate the flow of two components (CO2 and H2 O). A fluid model was built with the PR 78 EOS using WINPROP. A base case model without relative permeability hysteresis was simulated and compared with the case with relative permeability hysteresis. The amount of CO2 trapped, and CO2 saturation distribution were analyzed for maximum trapped gas saturation of 0.3, 0.4 and 0.5. Results shows an increase in the amount of CO2 trapped as the maximum residual gas saturation was increased from 0.3 to 0.4 and 0.5 with a value of 16560128mol for the base case study, 49041744mol, 59502924mol and 67286728mol respectively for maximum residual gas saturation due to relative permeability hysteresis of 0.3, 0.4 and 0.5 respectively. Very little accumulation of CO2 occurs when the maximum trapped gas saturation due to relative permeability hysteresis was set at 0.5. Result reveals that after 200 years, almost all the CO2 was trapped in the formation. Therefore, the imbibition cycle at the trailing end of the CO2 plume should be considered as accounting for hysteresis effects has led to a spread-out distrib

Experimental determination of gas-water relative permeability for ultra-low-permeability reservoirs using crushed-rock samples: Implications for drill cuttings characterization

Relative permeability controls fluid flow through rocks, with applications to hydrocarbon production, geologic carbon and energy storage. However, significant challenges are associated with the measurement of relative permeability for rocks with matrix permeability in the microdarcy to nanodarcy range. The primary objectives of this study are therefore to 1) propose an integrated experimental and modeling approach for gas relative permeability (krg) evaluation using crushed-rock samples and 2) perform a proof-of-concept study to demonstrate that gas–liquid relative permeability can be determined for ultra-low-permeability (unconventional) reservoir samples that have been crushed to certain grain sizes (20–35 mesh size).In this study, the water vapor ad-/desorption technique was employed to provide a wide range of water saturations (Sw). The evolution of water distribution in the shale matrix with a change in Sw was investigated by using a modified low-pressure adsorption (LPA) technique. A recently-developed numerical model was modified to estimate effective permeability to gas at each saturation level. Four clay-rich shales from the Duvernay (Canadian) and Kyalla (Australian) formations were analyzed.The vapor ad-/desorption technique provided an efficient approach to saturate the studied samples. By changing relative humidity in sealed desiccators using different salt solutions, a maximum Sw of 83% was obtained for organic-matter rich samples, and 99% for organic-matter lean shales. As interpreted using the modified LPA technique applied at different saturation levels, water is held in films in mineral-associated macro-/mesopores, and can block access to organic-matter pores through the formation of water clusters, significantly reducing the accessible organic-matter porosity and gas effective permeability. Imbibition krg decreases rapidly and significantly (over 90%) when Sw reaches approximately 0.3–0.4 for samples containing significant amounts of water-sensitive clay minerals (Kyalla #2) and TOC (Duvernay #2). Relative permeability hysteresis occurs for Duvernay #2 and Kyalla #1. Overall, the use of crushed-rock samples (non-matrix/fracture system), and application of the vapor sorption technique, results in a small amount of hysteresis.A laboratory-based method for measuring gas relative permeability of ultra-low-permeability reservoirs using crushed-rock samples is provided for the first time, with important applications to the energy and carbon capture industries.

“Extreme utilization” theory and practice in gas storages with complex geological conditions

Based on more than 20-year operation of gas storages with complex geological conditions and a series of research findings, the pressure-bearing dynamics mechanism of geological body is revealed. With the discovery of gas-water flowing law of multi-cycle relative permeability hysteresis and differential utilization in zones, the extreme utilization theory targeting at the maximum amount of stored gas, maximum injection-production capacity and maximum efficiency in space utilization is proposed to support the three-in-one evaluation method of the maximum pressure-bearing capacity of geological body, maximum well production capacity and maximum peak shaving capacity of storage space. This study realizes the full potential of gas storage (storage capacity) at maximum pressure, maximum formation-wellbore coordinate production, optimum well spacing density match with finite-time unsteady flow, and peaking shaving capacity at minimum pressure, achieving perfect balance between security and capacity. Operation in gas storages, such as Hutubi in Xinjiang, Xiangguosi in Xinan, and Shuang6 in Liaohe, proves that extreme utilization theory has promoted high quality development of gas storages in China.

Effect of relative permeability hysteresis on reservoir simulation of underground hydrogen storage in an offshore aquifer

Underground hydrogen storage (UHS) in porous media is proposed to balance seasonal fluctuations between demand and supply in an emerging hydrogen economy. Despite increasing focus on the topic worldwide, the understanding of hydrogen flow in porous media is still not adequate. In particular, relative permeability hysteresis and its impact on the storage performance require detailed investigations due to the cyclic nature of H2 injection and withdrawal. We focus our analysis on reservoir simulation of an offshore aquifer setting, where we use history matched relative permeability to study the effect of hysteresis and gas type on the storage efficiency. We find that omission of relative permeability hysteresis overestimates the annual working gas capacity by 34 % and the recovered hydrogen volume by 85 %. The UHS performance is similar to natural gas storage when using hysteretic hydrogen relative permeability. Nitrogen relative permeability can be used to model the UHS when hysteresis is ignored, but at the cost of the accuracy of the bottom-hole pressure predictions. Our results advance the understanding of the UHS reservoir modeling approaches.

Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt

The hysteresis of relative permeability and capillary pressure need to be more widespread in academic studies, in order to understand how they can influence reservoirs with light oil and high pressure. These phenomena become extremely important to have a good prediction of oil production, considering that in many cases, the use of hysteresis in calculations can lead to a better prediction of oil recovery, allowing the exploration of certain fields. Thus, this study had as main objective the analysis of two hysteresis models (Killough and Larsen and Skauge) widely used in commercial software, in order to investigate the behavior of a light oil reservoir using a miscible WAG-CO2 process. Thus, to achieve this goal, a semi-synthetic reservoir, with characteristics similar to those found in the Brazilian pre-salt, was considered and was modeled using commercial software from CMG. Hysteresis reduces fluid permeability, which can generate two effects: increased local sweep efficiency of the oil and loss of injectivity. The former effect contributes to increased oil recovery, while injectivity loss can decrease oil sweep, reducing oil recovery. Furthermore, this work found that hysteresis can cause loss of gas and water injectivity, however this did not prevent hysteresis from increasing oil recovery compared to the case without hysteresis.

Impact of experimentally measured relative permeability hysteresis on reservoir-scale performance of underground hydrogen storage (UHS)

Underground Hydrogen Storage (UHS) is an emerging large-scale energy storage technology. Researchers are investigating its feasibility and performance, including its injectivity, productivity, and storage capacity through numerical simulations. However, several ad-hoc relative permeability and capillary pressure functions have been used in the literature, with no direct link to the underlying physics of the hydrogen storage and production process. Recent relative permeability measurements for the hydrogen-brine system show very low hydrogen relative permeability and strong liquid phase hysteresis, very different to what has been observed for other fluid systems for the same rock type. This raises the concern as to what extend the existing studies in the literature are able to reliably quantify the feasibility of the potential storage projects. In this study, we investigate how experimentally measured hydrogen-brine relative permeability hysteresis affects the performance of UHS projects through numerical reservoir simulations. Relative permeability data measured during a hydrogen-water core-flooding experiment within ADMIRE project is used to design a relative permeability hysteresis model. Next, numerical simulation for a UHS project in a generic braided-fluvial water-gas reservoir is performed using this hysteresis model. A performance assessment is carried out for several UHS scenarios with different drainage relative permeability curves, hysteresis model coefficients, and injection/production rates. Our results show that both gas and liquid relative permeability hysteresis play an important role in UHS irrespective of injection/production rate. Ignoring gas hysteresis may cause up to 338% of uncertainty on cumulative hydrogen production, as it has negative effects on injectivity and productivity due to the resulting limited variation range of gas saturation and pressure during cyclic operations. In contrast, hysteresis in the liquid phase relative permeability resolves this issue to some extent by improving the displacement of the liquid phase. Finally, implementing relative permeability curves from other fluid systems during UHS performance assessment will cause uncertainty in terms of gas saturation and up to 141% underestimation on cumulative hydrogen production. These observations illustrate the importance of using relative permeability curves characteristic of hydrogen-brine system for assessing the UHS performances.

WITHDRAWN: Experimental and numerical-modeling investigation of relative permeability hysteresis during cyclic injection-production in underground gas storage

WITHDRAWN: Experimental and numerical-modeling investigation of relative permeability hysteresis during cyclic injection-production in underground gas storage

Impacts of relative permeability hysteresis, wettability, and injection/withdrawal schemes on underground hydrogen storage in saline aquifers

Underground hydrogen storage (UHS) is a key strategy in the implementation of a large-scale hydrogen (H2) economy and promotion of renewable energy development/utilization. For UHS in water-wet saline aquifers, H2 displaces in-situ brine during injection; during well shut-in and H2 withdrawal,brine imbibes back into the flow paths where it displaces some H2. These processes are influenced by H2-brine transport physics, H2-brine-rock interactions and injection/withdrawal schemes, which, in turn, determine H2 storage capacities and injection/withdrawal efficiency. However, these effects are poorly understood. Therefore, this work focuses onthe impact of relative permeability hysteresis (RPH), wettability, and H2 withdrawal rate on UHS performance in a saline aquifer. Furthermore, differences between UHS and CO2 geo-storage (CGS) are examined.The primary findings include: 1) RPH results in a smaller H2 withdrawal factor (H2-WF), but a larger H2 withdrawal purity (H2-WP); 2) H2-WF increases with rock hydrophobicity, while H2-WP is mostly insensitive to rock wettability; 3) under similar storage conditions, H2-WF and H2-WP are approximately 10% less than CO2-WF and CO2-WP.These insights demonstrate the significance ofRPH and rock wettability on UHS performance and provides guidance on H2 injection/withdrawal scheme optimization. This study aids in the implementation of an industry-scale hydrogen economy.

Impact of geological and operational conditions on underground hydrogen storage

Transition toward renewable energies is an important step to tackle climate change and to build a sustainable energy system. Fluctuation in availability of renewable energy sources is a major issue leading to demand and supply imbalance. To solve this mismatch, surplus energy can be converted to green hydrogen (H2) through water electrolysis and be stored underground. Here we study the injection, storage, and production of H2 in a three-dimensional heterogeneous aquifer system. The goal is to understand how H2 storage is affected by vertical anisotropy ratio, temperature, injection and production period, relative permeability (kr) hysteresis, well perforation placement, and cushion gas type. For each case, we study how stored H2 is distributed in different forms: mobile, residually trapped, dissolved, and produced. We also quantify volume of extracted water. Results suggest that H2 recovery is successful if 1) the aquifer is more anisotropic and has lower temperature, 2) low density and viscosity cushion gas is injected prior to H2 storage, 3) injection and production perforations are placed at the bottom and top of aquifer, respectively, and 4) shut-in period between injection and production stages is minimized. Results demonstrate that kr hysteresis is critical to assess the amount of residually trapped H2.

Understanding Hysteresis and Gas Trapping in Dissociating Hydrate-Bearing Sediments Using Pore Network Modeling and Three-Dimensional Imaging

Hysteresis behavior is a key factor in exploring dynamic water and gas flow in dissociating hydrate-bearing sediments (HBS). In this study, we combined microfocus X-ray computed tomography and a pore network model to investigate the effect of hydrate dissociation on gas trapping and hysteresis in capillary pressure, Pc and relative permeability, kr in different wettability systems. The results show that the hydrate dissociation process involves secondary hydrate formation, which promotes gas trapping. The effective residual gas saturation in the water-wet system was significantly higher than that in the gas-wet system due to snap-off. Gas trapping has a huge impact on the hysteresis in Pc and kr between the drying and wetting cycles in HBS. This work will improve the fundamental understanding of the permeability properties of HBS so that gas and water production can be better assessed.

Physics-Based Proxy Modeling of CO2 Sequestration in Deep Saline Aquifers

The geological sequestration of CO2 in deep saline aquifers is one of the most effective strategies to reduce greenhouse emissions from the stationary point sources of CO2. However, it is a complex task to quantify the storage capacity of an aquifer as it is a function of various geological characteristics and operational decisions. This study applies physics-based proxy modeling by using multiple machine learning (ML) models to predict the CO2 trapping scenarios in a deep saline aquifer. A compositional reservoir simulator was used to develop a base case proxy model to simulate the CO2 trapping mechanisms (i.e., residual, solubility, and mineral trapping) for 275 years following a 25-year CO2 injection period in a deep saline aquifer. An expansive dataset comprising 19,800 data points was generated by varying several key geological and decision parameters to simulate multiple iterations of the base case model. The dataset was used to develop, train, and validate four robust ML models—multilayer perceptron (MLP), random forest (RF), support vector regression (SVR), and extreme gradient boosting (XGB). We analyzed the sequestered CO2 using the ML models by residual, solubility, and mineral trapping mechanisms. Based on the statistical accuracy results, with a coefficient of determination (R2) value of over 0.999, both RF and XGB had an excellent predictive ability for the cross-validated dataset. The proposed XGB model has the best CO2 trapping performance prediction with R2 values of 0.99988, 0.99968, and 0.99985 for residual trapping, mineralized trapping, and dissolution trapping mechanisms, respectively. Furthermore, a feature importance analysis for the RF algorithm identified reservoir monitoring time as the most critical feature dictating changes in CO2 trapping performance, while relative permeability hysteresis, permeability, and porosity of the reservoir were some of the key geological parameters. For XGB, however, the importance of uncertain geologic parameters varied based on different trapping mechanisms. The findings from this study show that the physics-based smart proxy models can be used as a robust predictive tool to estimate the sequestration of CO2 in deep saline aquifers with similar reservoir characteristics.

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.

Role of relative permeability hysteresis in modified salinity water flooding

Many laboratory and field scale trials have shown that modified salinity water flooding increases the mobility of oil and improves oil recovery. However, field scale simulation of the process guided by core flooding data leads to inaccurate prediction of oil recovery if the effect of the saturation history of the reservoir on relative permeability is ignored. Here, we address this problem by proposing three models illustrating the interplay among wettability alteration, hysteresis effect, and fluid flow transport in porous media. The models provide the variation of imbibition and secondary drainage saturation curves versus salinity caused by wettability alteration. Our simulations show that including hysteresis together with the wettability alteration process can better quantify the re-trapping of the oil that is mobilized due to wettability alteration of the reservoir. We further show that in the capillary transition zone, where water saturation varies from top to bottom of the reservoir, oil recovery continues for a long time, although the water cut starts early, in comparison with a reservoir with an initial uniform water saturation. Despite many experiments conducted for advanced waterflooding, our observations show that measuring the secondary drainage and imbibition saturation curves is essential and serves as a valuable input for the field scale simulation of modified salinity waterflooding of water flooded reservoirs with highly non-uniform saturation history.

Role of Relative Permeability Hysteresis in Modified Salinity Water Flooding

Role of Relative Permeability Hysteresis in Modified Salinity Water Flooding