Capillary Pressure Measurements Research Articles

Water blockage removal and productivity index enhancement by injecting thermochemical fluids in tight sandstone formations

Several challenges are associated with hydrocarbon production from tight reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered one of the main damaging mechanisms in tight reservoirs due to the increase of water saturation around the wellbore region and eventually decrease in the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. This paper presents a new technique to remove the water blockage from tight formations and improve the formation productivity using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples to enhance the flow conditions. Coreflooding experiments, capillary pressure, and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The productivity index for core samples were determined before and after the thermochemical flooding. The effect of thermochemical injection on reducing the capillary forces was analyzed by measuring the capillary pressure before and after the chemical treatment. The alteration in pore geometry due to the thermochemical flooding was evaluated using NMR measurements. The results of this study show that water blockage is a potential damage in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduced the capillary forces and removed the water banking. Flooding tight core samples with thermochemical resulted in generating tiny fractures in the treated samples, which reduces the capillary forces by 55.6% after the chemical treatment. The in-situ generated heat and nitrogen gas during thermochemical treatment can result in removing the water blockage from tight formations utilizing the desiccation effect. Also, thermochemical treatment showed a significant improvement in the core conductivity. The productivity index of core samples increased by 94.3% due to the chemical flooding. This study introduces a new chemical treatment for removing the water blockage from tight formations using environmentally friendly fluids. Thermochemical treatment improved the productivity index by a factor of 1.94 and decreased the drawdown pressure by more than 80%. Consequently, the trapped water was removed, and the total hydrocarbon production significantly improved.

Non-invasive and real-time measurement of microvascular barrier in intact lungs

Microvascular leak is a phenomenon witnessed in multiple disease states. In organ engineering, regaining a functional barrier is the most crucial step towards creating an implantable organ. All previous methods of measuring microvascular permeability were either invasive, lengthy, introduced exogenous macromolecules, or relied on extrapolations from cultured cells. We present here a system that enables real-time measurement of microvascular permeability in intact rat lungs. Our unique system design allows direct, non-invasive measurement of average alveolar and capillary pressures, tracks flow paths within the organ, and enables calculation of lumped internal resistances including microvascular barrier. We first describe the physiology of native and decellularized lungs and the inherent properties of the extracellular matrix as functions of perfusion rate. We next track changing internal resistances and flows in injured native rat lungs, resolving the onset of microvascular leak, quantifying changing vascular resistances, and identifying distinct phases of organ failure. Finally, we measure changes in permeability within engineered lungs seeded with microvascular endothelial cells, quantifying cellular effects on internal vascular and barrier resistances over time. This system marks considerable progress in bioreactor design for intact organs and may be used to monitor and garner physiological insights into native, decellularized, and engineered tissues.

A new correction method for mercury injection capillary pressure (MICP) to characterize the pore structure of shale

The economic and accurate measurement of micron or submicron size pores in shale is still a challenge. The mercury injection capillary pressure (MICP) measurement of shale particles is an effective method to evaluate the macropore structure, but it is questionable without proper data interpretation. In this study, the fractal theory was applied to identify the four stages of MICP measurement: Stage A is controlled by the interparticle voids in the particle assemblage; Stage B can reflect mercury intrusion into the pores of the shale; and Stage C and D indicate the shale matrix compression and pore structure change induced by high pressure, respectively. Based on the consistent fractal dimension derived from Stage A, the conformance volume induced by interparticle voids at each pressure step in Stage B was quantitatively simulated using the linear fitting method. The correction results show that simultaneous mercury filling of interparticle voids has an important impact on the pore volume in the pore size range larger than 1 μm. To cover the complete pore size range, the MICP data in Stage C and D were substituted by gas adsorption data.The new correction method for MICP data was verified by the good match between the MICP-gas adsorption combined porosity and the helium porosity of the same sample and by the good agreement between the pore size distribution (PSD) curves from the MICP and N2 adsorption measurements in their overlapped pore size range. Therefore, the MICP and gas adsorption methods can be used in conjunction to characterize the pore structure of shale in the complete pore size range. The application of this method is particularly good for the silty samples of lacustrine shale in the study area compared with the clayey samples. To further improve the convergence of different fluid injection methods, more efforts are needed to determine the optimum particle size class and optimum data interpretation model for different shale lithofacies.

Carbonate rocks resistivity determination using dual and triple porosity conductivity models

Abstract The rocks may be classified as Archie rocks or Non-Archie rocks, depending on the link between pore structure and resistivity of the rock. For carbonate rocks, keeping this factor in view, the applicability of Archie's law tends to be unreasonable and employing Archie's equation will ultimately lead to inaccurate estimates of the water saturation. Numerous investigators have reported models that forms a link between laboratory results and field well logs to determine water saturation in intricate pore systems. In case of complex systems, Archie's law fails to correctly define the resistivity-index curves. In addition, it is imperative to carry out investigations at lower saturation values in order to elaborate the non-Archie characteristics. This brings the dual and triple porosity conductivity models into the equation. As these models are essential in defining the considerable changes of the resistivity-index curves, both qualitatively and quantitatively. The linkage between the two models is depicted electrically in series or in parallel. Moreover, it is possible to have a combination of the two configurations. As a result, the experimental results can be modeled accurately using least parameters. This work presents two models to determine water saturation in carbonate rocks, containing dual and triple porosity systems. This study also investigates the impact of different influential parameters such as saturation exponents, conductivity ratios, and pore volume fraction of each network systems, on the new models. Finally, the effect of each parameter is individually studied and the sensitivity analysis on the RI curves is produced. A new approach to apply these models is also explained which requires the use of NMR log, mercury injection capillary pressure (MICP) measurement, and simple plotting techniques to determine the water saturation. The proposed new models help petrophysicists to estimate water saturation in Non-Archie rocks, containing double and triple porosity network systems.

Imbibition Capillary Pressure and Relative Permeability of Mixed-Wet Microporous Rock: New Insights from History Matching

MC was supported by the University of Aberdeen College of Physical Sciences studentship. The authors gratefully acknowledge CYDAREX for providing an evaluation license for their software CYDARTM , Koon-Yang Lee for the n-decane/brine static contact angle measurements on calcite (Supplementary Material S3), and Steffen Berg for his insightful comments and suggestions as a reviewer for conference paper Christensen and Tanino 2018 on which this paper builds. Finally, the authors thank the three anonymous reviewers for their detailed comments. All data used in this study are available from the corresponding author on reasonable request. In addition, the centrifuge data generated during this study are included as a Excel spreadsheet in the supplementary materials for this published article. One set of mercury injection capillary pressure measurements by Tanino and Blunt (2012) analysed in Text S2 are available in the Mendeley data repository, https://data.mendeley.com/datasets/9f4898jfr9/1.

LEFT ATRIAL STRAIN AS A SURROGATE MARKER OF ATRIAL CHAMBER STIFFNESS

Previous experimental studies show that left atrial (LA) stiffness is one of the determinants of LA reservoir function. However, it may be challenging to estimate LA stiffness in human. Echocardiography was performed simultaneously with measurements of pulmonary capillary wedge pressure (PCWP) in

Methods for process-related resin selection and optimisation in high-pressure resin transfer moulding

ABSTRACTA framework for process-related resin selection and optimisation is proposed in the context of research and development for industrial applications of high-pressure resin transfer moulding. The first stage involves validation of the reaction kinetics model by differential scanning calorimetry and characterisation of viscosity, storage- and viscous-shear moduli by dynamic mechanical analysis in a rheometer as a function of time. It also includes capillary pressure measurements of curing resin impregnating a fibre yarn. Process-related resin selection criteria are based on the optimisation of cycle time, including filling time against gel time, micro-infiltration time and demould time. The proposed framework and associated test and analysis methodologies are applied to three epoxy resin systems in connection with carbon fibre reinforcement.

Leveraging Device-Arterial Coupling to Determine Cardiac and Vascular State.

Limitations in available diagnostic metrics restrict the efficacy of managing therapies for cardiogenic shock. In current clinical practice, cardiovascular state is inferred through measurement of pulmonary capillary wedge pressure and reliance on linear approximations between pressure and flow to estimate peripheral vascular resistance. Mechanical circulatory support devices residing within the left ventricle and aorta provide an opportunity for both determining cardiac and vascular state and offering therapeutic benefit. We leverage the controllable mode of operation and transvalvular position of an indwelling percutaneous ventricular assist device to assess vascular and, in turn, cardiac state through the effects of device-arterial coupling across different levels of device support. Vascular state is determined by measuring changes in the pressure waveforms induced through intentional variation in the device generated blood flow. We evaluate this impact by applying a lumped parameter model to quantify state-specific vascular resistance and compliance and calculate beat-to-beat stroke volume and cardiac output in both animal models and retrospective patient data without external calibration. Vascular state was accurately predicted in patients and animals in both baseline and experimental conditions. In the animal, stroke volume was predicted within a total root mean square error of 3.71 mL (n = 482). We demonstrate that device-arterial coupling is a powerful tool for evaluating patient and state specific parameters of cardiovascular function. These insights may yield improved clinical care and support the development of next generation mechanical circulatory support devices that determine and operate in tandem with the supported organ.

CO2 Wettability of Sandstones: Addressing Conflicting Capillary Behaviors

AbstractUnderstanding the capillary and wetting behavior of supercritical CO2 (scCO2) and brine in reservoir rocks is crucial for reliable predictions of geologic carbon storage, as it strongly impacts CO2 migration and residual trapping in the reservoir. The wetting state of such systems can be assessed through laboratory measurements of the capillary pressure characteristic curve. However, while some studies reported consistent scaling with strongly water wet systems, some others observed deviations from hydrophilic conditions. We present core‐flooding drainage capillary pressure measurements using scCO2/water and N2/water on a Berea sandstone, untreated, then fired, and then exposed to scCO2 for 28 days. The purpose is to investigate the impact of firing and longer exposure to scCO2, two potential sources for variability in experimental observations, on capillarity and wettability. The results show excellent agreement among all the core‐flooding capillary pressure data, suggesting no change in wetting state due to firing or longer exposure.

Measurement of Spontaneous Imbibition Capillary Pressure, Saturation and Resistivity Index by Counter Current Technique at Net Reservoir Stress and Elevated Temperature

Capillary pressure and resistivity index spontaneous imbibition experiments by the porous plate method, in a core holder at elevated temperature and net reservoir stress, are both difficult and time consuming special core analysis measurements to perform. In this type of experiment, low capillary forces act against a low permeable porous plate and only one face of the cylindrical core sample is in capillary contact with the fluid saturated porous plate. In this paper, core samples having different lithology, petrophysical properties and wettability are analysed by counter current spontaneous imbibition, starting at initial water saturation (Swi), at net confining pressure and elevated temperature. Synthetic brine is used as the wetting phase and Isopar L mineral oil as the non-wetting phase. This methodology is applied to investigate and evaluate how to obtain more reliable, more efficient and faster saturation imbibition data combined with electrical measurements, during spontaneous imbibition measurements. Resistivity index (RI), saturation exponent (n) (by single saturation equilibrium point using Archie’s second law RI= Sw-n) and wettability information using representative fluids, confining pressure and temperature are also obtained by applying this specific counter current imbibition technique and improved procedural approach.

A fast method for trapped gas determination

Gas reservoirs are mainly produced by depletion with an aquifer rise; reservoir simulation requires two main SCAL inputs: the amount of trapped gas by the aquifer (residual gas saturation: Sgr) and the relative permeability to water due to aquifer flooding. As it is quasi impossible to predict aquifer strength, the primary SCAL input for reservoir simulation is the Sgr. The recovery factor is directly defined by initial and residual gas saturations. In fact, the residual gas saturation Sgr highly depends on the initial gas saturation Sgi and there is no universal petrophysical parameter governing the shape of this curve. This relationship can be described by several different models (Land, Aissaoui…). While Land’s model is widely used, the Aissaoui model better fits the experimental results (Suzanne et al. 2003), at least for homogeneous sandstones. For a given threshold of initial gas saturation Sg0, this relationship typically exhibits a plateau at high Sgi>Sg0 and an increasing linear trend at low Sgi<Sg0. The challenge here is to properly estimate the value of the Sg0 threshold. Classical laboratory method would require one experiment per point in the Sgr/Sgi plot, and therefore can be achieved in a matter of months. Here we propose a laboratory method allowing the acquisition of the Sgr/Sgi curve in a few days. The proposed method combines centrifugation and capillary rise under imaging. First, the centrifuge allows creating a saturation profile along a sample; measured by NMR. Then, capillary rise is used to capture Sgr under NMR monitoring. By adding NMR imaging, this technique allows combining the benefits of centrifugation to explore a wide range of Sgi; and the ease and cost effectiveness of capillary rise to measure the resulting Sgr. Therefore, at a timescale close to a traditional capillary rise, the proposed technique avoids Land extrapolation and provides a direct measurement of Sgr in a wide range of Sgi. As an additional benefit, the combination of NMR and centrifuge can provide at the same time a direct measurement of capillary pressure, providing information on the gas in place and potential imbibition process in the reservoir.

Exponential Capillary Pressure Functions in Sedimentary Rocks

The Brooks-Corey power-law capillary pressure model is commonly imposed on core analysis data without verifying the validity of its underlying assumptions. The Brooks-Corey model, originally developed to model the pressure head during the drainage of soil, is only valid at low wetting phase saturations. However, such models are often applied in petroleum production simulations and may lead to erroneous recovery factors when the saturation range of interest is far from the end points. We demonstrate that exponential models work much better for capillary pressure compared to the Brooks-Corey model over a wide saturation range. Mercury injection porosimetry, petrographic image analysis, and magnetic resonance studies suggest that the pore and throat size distribution in many rocks are log-normally distributed. This fact was previously employed to calculate the capillary pressure function as a function of saturation for pore size distributions described by atruncated log-normal distribution. Employing a Taylor series expansion, we simplify the random fractal capillary pressure model of Hunt to Pc = exp(a − bS), where S is the wetting phase saturation, and a and b characteristic of the porous medium. An extensive dataset of seventeen centrifuge capillary pressure measurements were used in this research to demonstrate the merit of the new method. For both sandstones and carbonates, the logarithm of capillary pressure showed a linear relationship with saturation as observed by magnetic resonance imaging centrifuge capillary pressure measurements over a wide saturation range. This work demonstrates that: (a) in semi-log plots of capillary pressure as a function of saturation, capillary pressurewill vary linearly over a wide saturation range, (b) such a plot as described in (a) will show the uni-or bimodal pore size distribution of the rock, (c) the exponential capillary pressure function simplifies analytical modelsthat use the capillary pressure function, for example oil recovery models for fractured reservoirs.

Simulation of Capillary Pressure Overshoot in Snow Combining Trapping of the Wetting Phase With a Nonequilibrium Richards Equation Model

AbstractThe timing and magnitude of snowmelt discharge and subsequent runoff are controlled by both matrix and preferential flows of water through snowpacks. Matrix flow can be estimated using the Richards equation, and recently, preferential flow in snowpacks has been represented in 2D and 3D models. A challenge for representing preferential flow through porous media in 2D or 3D is capillary pressure overshoot in 1D. Soil studies have developed sophisticated and largely realistic approaches to represent capillary pressure overshoot, but it has not been addressed in snowpack water flow models. Here a 1D nonequilibrium Richards equation model is implemented with dynamic capillary pressure and is combined with a new concept of entrapment of liquid water within the pore space. This new model well represented capillary pressure overshoot, as estimated by published capillary pressure measurements in snow samples of various grain sizes under different rates of liquid water infiltration. Three model parameters were calibrated, and their impacts on model outputs were evaluated. This improvement is a substantial step toward better understanding and simulating physical processes occurring while liquid water percolates an initially dry snowpack.

Assignment and calibration of relative permeability by hydrostratigraphic units for multiphase flow analysis, case study: CO2-EOR operations at the Farnsworth Unit, Texas

Among the most critical factors for geological CO2 storage site screening, selection, and operation is effective simulations of multiphase flow and transport. Relative permeability is probably the greatest source of potential uncertainty in multiphase flow simulation, second only to intrinsic permeability heterogeneity. The specific relative permeability relationship assigned greatly impacts forecasts of CO2 trapping mechanisms, phase behavior, and long-term plume movement. A primary goal of this study is to evaluate the impacts and implications of different methods of assigning relative permeability relationships for CO2-EOR model forecasts.Most simulation studies published in the literature base selection of relative permeability functions on the geologic formation or rock type alone. In this study, we initially implemented reservoir model grids with previously-identified hydrostratigraphic units based on porosity and permeability relationship of the Morrow ‘B’ Sandstone, then assigned relative permeability functions for those hydrostratigraphic units. Specific, constrained relative permeability relationships were created and assigned to each hydrostratigraphic unit using petrophysical data and Mercury Intrusion Capillary Pressure (MICP) measurements, from core samples of each hydrostratigraphic unit. Results of forward simulations with the newly-calibrated models will be compared to those of previous models as well as to simulation results for a range of different relative permeability relationships.The study site is the Farnsworth Unit (FWU) in the northeast Texas Panhandle, an active CO2-EOR operation. The target formation is the Morrow ‘B’ Sandstone, a clastic formation composed of medium to course sands.

The second critical capillary number for chemical flooding in low permeability reservoirs: Experimental and numerical investigations

High capillary numbers are often adopted for chemical flooding in reservoirs to achieve the highest oil recovery. A high capillary number may be disadvantageous for high and medium permeability formations, while no experimental or field data are available for low permeability formations. In this work, through the use of a newly designed experimental apparatus for the measurement of the dynamic capillary pressure in low permeability formations, chemical flooding experiments on sandstone core samples (1–10 mD) were conducted to investigate the effects of high capillary numbers (0.001–2). In addition, these effects were examined through numerical production simulations on a real low permeability reservoir. The dynamic capillary pressure and relative permeability were measured to reveal the dynamic fluid flow characteristics. The dynamic contact angle was investigated to explore the dynamic interface properties. The results show that there is a second critical capillary number (higher than 0.02) that can be used to optimize the chemical flooding performance in low permeability reservoirs. Moreover, the oil relative permeability reaches its highest value at the second critical capillary number, while the water relative permeability always increases with the increase in the capillary number. The dynamic contact angle will reach approximately 180° at a high capillary number, causing an oil film to remain. An optimized capillary number range is proposed for chemical flooding in low permeability reservoirs.

Exercise capacity in COPD patients with exercise-induced pulmonary hypertension

BackgroundPulmonary hypertension (PH) in patients with COPD is associated with reduced exercise capacity. A subgroup of COPD patients has normal mean pulmonary artery pressure (mPAP) at rest, but develops high mPAP relative to cardiac output (CO) during exercise, a condition we refer to as exercise-induced pulmonary hypertension (EIPH). We hypothesized that COPD patients with EIPH could be identified by cardiopulmonary exercise test (CPET) and that these patients have lower exercise capacity and more abnormal CPET parameters compared to COPD patients with normal hemodynamic exercise response.MethodsNinety-three stable outpatients with COPD underwent right heart catheterization with the measurement of mPAP, CO, and capillary wedge pressure at rest and during supine exercise. Resting mPAP <25 mmHg with ΔmPAP/ΔCO slope above or below 3 mmHg/L/min were defined as COPD-EIPH and COPD-normal, respectively. Pulmonary function tests and CPET with arterial blood gases were performed. Linear mixed models were fitted to estimate differences between the groups with adjustment for gender, age, and airflow obstruction.ResultsEIPH was observed in 45% of the study population. Maximal workload was lower in COPD-EIPH compared to COPD-normal, whereas other CPET measurements at peak exercise in % predicted values were similar between the two groups. After adjustment for gender, age, and airflow obstruction, patients with COPD-EIPH showed significantly greater increase in oxygen uptake, ventilation, respiratory frequency, heart rate, and lactate with increasing work load, as well as more reduction in pH compared to those with normal hemodynamic responses.ConclusionCOPD-EIPH could not be discriminated from COPD-normal by CPET. However, COPD-EIPH experienced a higher cost of exercise in terms of higher oxygen uptake, ventilation, respiratory frequency, heart rate, and lactate for a given increase in workload compared to COPD-normal.

Measurements of capillary pressure and relative permeability curves for foam transport in porous media-A capillary bundle approach

Foam mobility in porous media is governed by bubble texture, foam trapping, bubble generation, and bubble coalescence. Published reports showed that foam mobility is dominated by foam trapping in the transient flow regime or low capillary pressures (Pc), while bubble coalescence dominates foam flow in the steady state regime or higher Pc. An efficient foam model is expected to capture all these pore scale phenomena. However, most of the available models do not adequately account for foam trapping behavior because their model parameters are usually determined from coreflood experiments at steady state flow regimes. Hence, they are unsuitable for simulating transient foam flow behavior. Some mechanistic population balance models incorporate the effect of foam trapping on gas mobility through the relative permeability (Kr) function such that the Kr of the flowing foam is a function of only the flowing foam saturation. However, a constitutive equation is required to predict the flowing foam fraction. Some of the variables in this equation are also obtained from experimental data at steady state, while there is no known experimental method to measure other variables. In this paper, a novel coreflood method is presented that allows flowing foam fraction to be measured directly at different Pc and water saturations during foam flow. A consolidated porous medium was treated like a bundle of capillaries of various sizes, by modifying the surfactant alternating gas (SAG) method of foam injection. An electrical resistivity tool monitored in-situ saturation changes while a high resolution pressure transducer measured the pressure drop across rock samples. Multiple SAG cycles generated a data array of trapped and flowing foam as a function of water saturation and capillary pressure, which was then used to generate Pc and Kr curves. The Pc and Kr curves exhibit behavior that are consistent with established physics of foam flow in porous media. The measured Pc curves also compared well with porous plate Pc measurements, which thus validates the accuracy of the methodology in treating a consolidated porous medium as a bundle of capillaries. The measured foam limiting capillary pressure values also showed a good trend with those reported in the literature. The critical water saturation for foam was much higher than the connate water saturation measured from the porous plate method. Finally, it was shown that this method has a strong potential to be implemented at a field scale.

Modeling of the cementation factor and hydraulic permeability using Mercury Injection Capillary Pressure (MICP) measurements

Electrical models of the porous medium are widely used for the estimation of the volume fraction of fluids filling in the pore space. One of the input parameters into this type of models is the geometrical factor associated with the complexity of the pore network system also known as “cementation factor” used in Archie's saturation model. While this parameter can be measured in the laboratory, the aim of this work is to infer it from the pore size distribution (PSD), which in itself does not bear any information about the geometry of the 3D pore network. The proposed probabilistic model assumes a predefined geometry of the elementary cell, and uses PSD obtained from the Mercury Injection Capillary Pressure (MICP) measurements and porosity to predict the cementation factor. The model achieved a good agreement with an average value of the cementation factor measured on the numerous core samples obtained from the two fields investigated in this study. Geometrical considerations were also investigated through introduction of tortuosity and shape of the capillaries in the model to allow for the potential lithological variations of the reservoir rocks. Similar approach was used to estimate hydraulic permeability using the probabilistic model, and the results were tested against air permeability values measured in the laboratory.

Slippage in shale based on acyclic pore model

A significant fraction of the pore-throat size in the matrix of a shale formation is smaller than 100 nm. Nanofluidics, a field that deals with the transport properties of sub-100-nm conduits, indicates that the fluid flow is enhanced for this range of pore-throat size. However, it is unclear how the slippage at the pore scale (single conduit) controls the effective slippage at the core scale (∼1 in.). The present study reviews the slippage models for the gas and liquid flows inside a single conduit based on the experimental and theoretical studies in the literature. It then investigates the effective enhancement in shale formations using an acyclic pore model, which represents the effective connectivity of the shale pore space at the core scale as it captures the mercury injection capillary pressure measurements (drainage). The effective slippage is presented in terms of governing parameters such as pore pressure and wettability. This study presents the effective pore-throat size, whose corresponding slippage is equal to the effective gas slippage at the core scale, for three shale samples. The numerical simulations indicate that the effective pore-throat size for the gas flow depends on the pore pressure. In addition, the measured permeability with liquid is higher than the nominal permeability, often referred to as the Hagen–Poiseuille model, with no slippage. The presented results have major implications for reservoir characterization based on standard petrophysical measurements.

Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance

CO2 enhanced oil recovery (EOR) has been carried out in the Bell Creek oil field since 2013. Together with the encouraging oil production results, a considerable quantity of CO2 has also been trapped in the reservoir as a normal part of the EOR process, also referred to as associated storage. Because of the complex geologic conditions in the field, a series of experimental and modeling work have been conducted to better understand the CO2 EOR and associated storage performance in the reservoir. Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance are thoroughly investigated in this study.A proportion of injected CO2 remains behind through residual and solubility trapping mechanisms when CO2 flows through a reservoir during a CO2 EOR process. Over 50 core plugs were collected from the reservoir to characterize the rock properties. Mineralogical analysis and capillary pressure measurements showed that the mineral composition and pore-size distribution in the reservoir are favorable for residual trapping of CO2. The hysteresis of gas relative permeability was measured to assess the effect of residual trapping on associated CO2 storage using steady-state relative permeability tests and reservoir simulation. The reservoir oil was characterized based on pressure–volume–temperature experiments and Peng–Robinson equation of state modeling, which showed that CO2 solubility in oil is much greater (≥5 times) than in water. Results indicated that depleted oil reservoirs have great potential to store a huge quantity of CO2 associated with EOR operations, as residual oil saturation is 0.3 or greater in most conventional oil reservoirs after water flooding.