Enhanced Oil Recovery Research Articles

Spontaneous imbibition characteristics and influencing factors of shale oil reservoir in Qintong depression

This study integrates one-dimensional and two-dimensional nuclear magnetic resonance (NMR) techniques to conduct spontaneous imbibition experiments on two distinct lithologies (laminated calcareous shale and bulk clay-rich shale) from the Qintong Depression using four different fluid types. Field emission scanning electron microscopy (FE-SEM) and computed tomography (CT) scanning were employed to observe and track the dynamic changes in shale microstructures at specific intervals allowing for a comprehensive analysis of induced microfractures and their propagation patterns. These methods enabled a deeper understanding of the underlying mechanisms, enriching the interpretation of the imbibition results. The study reveals that anionic surfactants demonstrate exceptional performance during the imbibition process, and the combination of surfactants further enhanced oil recovery. The imbibition process can be divided into three stages: the imbibition diffusion stage, the transition stage, and the equilibrium stage, with the diffusion stage serving as the primary contributor, driven predominantly by capillary pressure. The calcareous shale cores exhibited the highest imbibition rates in the early stages, approaching equilibrium in the middle stages. Conversely, the clay-rich shale cores maintained relatively high imbibition rates throughout the second stage, indicating different imbibition dynamics based on lithology. NMR, CT scanning, and SEM analysis highlighted significant lithology-dependent differences in the mechanisms driving induced microfracture development during the imbibition and hydration. In laminated calcareous shale, imbibition and hydration primarily proceeded through the dissolution of calcareous minerals, resulting in pore expansion and induced microfractures along pre-existing fractures. In contrast, clay-rich shale exhibited similar mineral dissolution but also experienced clay swelling due to its high clay content, leading to the formation of bedding-parallel fractures with distinct directional patterns along weak mineral-matrix bonds. The experimental results underscored the pivotal role of lithology in determining final imbibition efficiency, with high-clay-content shales demonstrating superior recovery rates under spontaneous imbibition conditions. This study provides critical experimental data and insights into the microscopic mechanisms governing spontaneous imbibition across varied lithologies and fluid types in the Qintong Depression. The results offer foundational knowledge for optimizing oilfield development strategies.

Molecular Dynamics Simulation of the Effect of Shale Wettability on CO2 Enhanced Oil Recovery.

The wettability of shale is an important factor affecting oil and gas extraction, and conventional experimental methods are difficult to study at the nanoscale. Moreover, most existing studies are qualitatively based on the wettability of rock surfaces with little consideration for their impact on the CO2-EOR. This study employs molecular dynamics simulation methods to conduct an in-depth analysis of the role of rock surface wettability in the CO2-enhanced oil recovery (EOR) process. The research findings indicate that as the surface hydroxyl content increases, the adsorption affinity for CO2 is enhanced, with the selectivity increasing exponentially from 0.74 in the strongly oleophilic wetting (SOW) pore to 3.62 in the strong hydrophilic wetting (SHW) pore. Additionally, variations in wettability result in different types of CO2 displacement. As oil wettability decreases, the contact interface between CO2 and oil changes from a convex to a concave shape. Moreover, different types of wettability result in different dynamic contact angle changes over time, which significantly impacts various displacement stages. A comprehensive comparison shows that pores exhibiting oil-wet characteristics reduce the efficiency of the CO2-EOR. Finally, the investigation explored the influence of pore structure on oil displacement efficiency. In double pores, when the larger pores exhibit hydrophobic characteristics, they further accelerate the displacement speed of the smaller pores. In connected pores, the presence of notch speeds up the displacement effect within the smaller pores, reducing the impact of wettability on displacement efficiency. This study deeply analyzes the role of shale surface wettability in the CO2-EOR process, revealing the impact of wettability on the CO2 adsorption affinity, fluid displacement, oil displacement efficiency, and flow characteristics of shale oil, providing an important theoretical basis for optimizing the CO2-EOR process by adjusting wettability.

Experimental Study on the Mechanism of Enhanced Imbibition with Different Types of Surfactants in Low-Permeability Glutenite Reservoirs

Due to the complex physical properties of low-permeability glutenite reservoirs, the oil recovery rate with conventional development is low. Surfactants are effective additives for enhanced oil recovery (EOR) due to their good ability of wettability alteration and interfacial tension (IFT) reduction, but the reason why imbibition efficiencies vary with different types of surfactants and the mechanism of enhanced imbibition in the glutenite reservoirs is not clear. In this study, the imbibition efficiency and recovery of surfactants including the nonionic, anionic, and cationic surfactants as well as nanofluids were evaluated and compared with produced water (PW) using low-permeability glutenite core samples from the Lower Urho Formation in the Mahu oil field. Experiments of IFT, wettability, emulsification, and imbibition at high-temperature and high-pressure were conducted to reveal the underlying EOR mechanisms of different types of surfactants. The distribution and utilization of oil in different pores during the imbibition process were characterized by a combined method of mercury intrusion and nuclear magnetic resonance (NMR). The main controlling factors of surfactant-enhanced imbibition in glutenite reservoirs were clarified. The results demonstrate that the micropores and mesopores contribute most to imbibition recovery in low-permeability glutenite reservoirs. The anionic surfactant KPS exhibits a good capacity of reducing IFT, wettability alteration, and oil emulsification with the highest oil recovery of 49.02%, 8.49% higher than PW. The nonionic surfactant OP-10 performs well on oil emulsification and wetting modification with imbibition recovery of 48.11%. This study sheds light on the selection of suitable surfactants for enhanced imbibition in low-permeability glutenite reservoirs and improves the understanding of oil production through enhanced imbibition.

Molecular dynamics simulation of microscopic interaction mechanism between oil–water interface by modified graphene oxide oil displacement agent

With the increasing worldwide energy demand, enhanced oil recovery (EOR) is becoming more critical for oil fields. In recent years, the rise of nanotechnology has provided a new direction for developing oil repellents in low-permeability reservoirs, and the new nanomaterial-modified graphene oxide (MGO) has demonstrated good EOR performance in oil and gas field development. In this work, molecular dynamics simulations were carried out to investigate the influence of MGO on the interfacial tension (IFT) of oil water and its microscopic interaction mechanism. The impact of different grafting ratios and lengths of modified NPs on the interfacial properties of oil–water interfaces and their mechanisms were further analyzed. Simulation results indicate that, due to their amphiphilic structure, they are attracted to the oil phase and can spontaneously migrate to the oil–water interface. They form a dense monolayer film structure at the oil–water interface, reducing the IFT from 52.08 mN·m−1 thickness to 28.03 mN·m−1 by increasing the thickness of the oil–water interface. The most significant reduction in IFT was observed when MGO was grafted with sixteen-alkyl-long chains. The molecular-level insights gained from this study can provide valuable guidance for designing modified nanoparticles suitable for EOR applications.

Experimental Investigation of CO2 Huff-and-Puff Enhanced Oil Recovery in Fractured Low-Permeability Reservoirs: Core-Scale to Pore-Scale

To understand the impact of CO2 huff-and-puff on oil mobilization in tight reservoirs with varying fracture scales, we performed nuclear magnetic resonance (NMR) and microscopic visualization experiments, focusing on different fracture sizes and multi-scale fracture conditions. Our study investigates how different fracture sizes and densities influence the efficiency of CO2 huff-and-puff techniques in these environments. The results show that in scenarios with a single fracture, larger fracture apertures significantly boost oil mobilization within the fracture and the surrounding matrix. For instance, increasing the aperture from 20 μm to 70 μm improved the recovery factor by 9.20%. In environments with multiple fractures, greater fracture density enhances reservoir connectivity, and increases the CO2 sweep area, and the complex fracture model shows a 4.26% increase in matrix utilization compared to the simple fracture model. Notably, the improvement in recovery due to multi-scale fractures is most significant during the first two huff-and-puff cycles, with diminishing returns in subsequent cycles. Overall, increasing both fracture size and density effectively enhances crude oil mobilization in tight reservoirs. These findings provide valuable insights into improving the recovery efficiency of CO2 huff-and-puff techniques in tight oil reservoirs.

Formulation of Polymer-Augmented Surfactant-Based Oil–Water Microemulsions for Application in Enhanced Oil Recovery

Formulation of Polymer-Augmented Surfactant-Based Oil–Water Microemulsions for Application in Enhanced Oil Recovery

Molecular Dynamics of CO₂ Stripping Oil on Quartz Surfaces

The CO2-enhanced oil recovery (EOR) technology has the dual significance of enhancing oil recovery and realizing carbon storage in onshore and offshore oil and gas exploitation. This study investigates the adsorption of crude oil components on quartz surfaces and the microscopic mechanisms of CO2 stripping from crude oil using molecular dynamics simulations. A four-component model representing C6H14, benzene, resins, and asphaltenes was constructed to simulate the oil phase, while the quartz surface model was created using Materials Studio. Simulations were conducted under different temperature conditions to understand the distribution and adsorption behavior of crude oil components, as well as the impact of CO2 on the oil film at pressures up to 10 MPa. The results indicate that the resin–asphaltene interactions are significantly weakened at elevated temperatures, affecting the adsorption capacity. Furthermore, CO2 stripping primarily extracts light components such as C6H14 and aromatic hydrocarbons, while heavy components remain in the oil phase. The highest extraction efficiency and expansion effect of CO2 were observed at 35 °C, demonstrating optimal conditions for enhanced oil recovery through CO2 flooding. These findings provide insights into the effective use of CO2 for crude oil extraction and its interactions with oil components on a quartz substrate, which is crucial for optimizing CO2-enhanced oil recovery operations.

Design of CO2 Huff-n-Puff Parameters for Fractured Tight Oil Reservoirs Considering Geomechanical Effects

CO2-Huff-n-Puff (CO2-HnP) is an effective method for improving oil recovery in conventional reservoirs and has been widely applied to tight oil reservoirs. Recently, there has been a series of studies published on the oil increase mechanism and huff-n-puff parameter optimization of CO2-HnP. However, the understanding of the influence of fracture characterization, threshold pressure gradient (TPG), and geomechanical effects on CO2-HnP in fractured tight oil reservoirs is still limited. In this paper, a numerical model based on the embedded discrete fracture model (EDFM) was constructed to investigate the impact of TPG and geomechanical effects on cumulative oil production (COP). The effects of various huff-n-puff parameters, including bottomhole pressure, oil recovery rate, total CO2 injection amount, number of huff-n-puff cycles, timing of production transfer injection, production time, injection time, CO2 injection rate, and soaking time on the COP and oil replacement ratio were also explored in the paper. The results include the following: (1) The TPG and geomechanical effects led to significantly reduced COP. (2) A positive correlation with COP was found for parameters such as timing of production transfer injection and production time, while negative correlations were found for cycles, soaking time, and injection rate. For oil replacement ratio, soaking time and injection rate were positively correlated, while CO2 injection amount and number of cycles showed negative correlation. (3) With a constant injection volume, it is crucial to avoid an excessive number of cycles that reduce COP. On the basis of this parameter optimization, the oil replacement ratio can be enhanced by advancing the production transfer injection, shortening the injection time, and extending the soaking time. The findings can help optimize CO2-HnP strategies to improve oil recovery and economic benefits from the reservoir. This paper provides an effective numerical simulation method for CO2-HnP in fractured tight oil reservoirs, which has certain reference value.

Design innovative perspectives of thermally radiative flow of chemically reactive magnetized nanofluid capturing bioconvection and Joule heating aspects

The distinguishing thermophysical features of nanofluids make them possibly advantageous in enhancing transfer of heat. The applications of nanofluids in industrial cooling, cooling tower detection, imaging, microelectronic cooling, crossbreed motor proficiency, transparent sunscreen, crack-resistant paint, nuclear reactor cooling, thermal transport, enhanced oil recovery, and architecture have diversified extensively in recent years. Scientific research has shown an enormous spike in fascination with non-Newtonian nanofluids in the past few decades. The stress in non-Newtonian fluids varies nonlinearly with the rate of deformation. These fluids are used in material processing, bioengineering, polymeric fluids, oil reservoir design, and the chemical and nuclear industries. There have been several non-Newtonian models presented forth. The Williamson fluid model is one example of such a model that has a shear-thinning behavior. The current article explanate analysis of (3D) Williamson fluid flow considering various physical features which plays vital role to raise the heat transportation rate. Through transformations procedure the governing physical problem is simplified and then solved via bvp4c in MATLAB. Acquired data are tabulated and graphically presented, and the impacts of relevant parameters on concentration-microorganisms and temperature have been examined numerically. According to the accomplishments, the concentration profile is anticipated to decline as the stretching rate parameter and Brownian motion parameter values grow. By boosting the magnetic parameter, the microorganism profile advances, but the bioconvection Peclet number reveals an opposite tendency.

Molecular Dynamics Simulation on Slippage Effect and Injection Capacity With Hydrophobic Nanoparticles Adsorption

ABSTRACTWith the continuous exploitation of global oil and gas resources, the focus of oilfield development has gradually shifted to low‐permeability and tight reservoirs. Nowadays the nanofluid has become one of the most important methods to enhance oil recovery in low‐permeability reservoir since the wettability and fluid flow characteristics can be changed as hydrophobic nanoparticles are adsorbed on the surface. In this study, we focus on the fluid slip characteristics feature of nanoparticles adsorbed with different adsorption degrees through molecular dynamics methods. Our results show that the adsorption of hydrophobic nanoparticles on the wall induces a velocity slip effect. The fluid flows in a Cassie state in the micro‐channel, with a significant increase in density, velocity, and slip length. In addition, the velocity in the mainstream area is significantly greater than that near the wall. The fluid flow rate within the pore channel is maximized and the most optimal adsorption degree is around 65.08%. Meanwhile, this study provides not only of great significance for the microscopic mechanism of pressure reduction and injection enhancement technology by nanoparticles adsorbed, but also an efficient method in enhance oil recovery in low‐permeability oil reservoirs.

Experimental Study on the Alternate Oil Displacement Mechanism of CO2 and Modified Water in Low-Permeability Oil Layers

Alternating carbon dioxide and water flooding can not only seal greenhouse gases, but also combine the advantages of water flooding and carbon dioxide flooding, and can well control mobility and stabilize the displacement front, thereby greatly improving the macro-replacing efficiency. In order to further improve the development effect of water–carbon dioxide alternating flooding, this paper, based on sufficient collection of the literature, research, and analysis, pre-uses modified water instead of water, and deeply explores and studies the impact of modified water–carbon dioxide alternating flooding on the improvement of development effect and the mechanism of enhancing oil recovery in low-permeability reservoirs. The main work completed is as follows: (1) A comparative experiment of multiple groups of sand-filled tubes with different displacement media, modified water concentrations, and injection plug sizes was conducted under the conditions of simulating reservoir formation temperature of 70 °C and formation pressure of 18 MPa, and the optimal scheme and injection parameters of alternating modified water and carbon dioxide flooding were rationally selected. The results show that the alternating flooding of modified water and carbon dioxide in low-permeability reservoirs can significantly improve the development effect. The optimal injection parameters are a formulation concentration of 0.3% and an injection method of alternating a 0.1 PV slug injection of carbon dioxide and modified water. (2) Using Berea cores instead of sand-fill tubes, a comparative experiment of alternating oil displacement using carbon dioxide and modified water was carried out under the same experimental conditions. Nuclear magnetic resonance measurements were performed on five of the cores to analyze the microscopic oil displacement mechanisms of different displacement media. The results show the following: nuclear magnetic resonance testing shows that carbon dioxide displacement can greatly improve the oil recovery efficiency in tiny pores (about 47.43%); alternating injection can further improve the oil recovery efficiency in tiny pores (about 70.6%); and modified water can improve the oil recovery efficiency in larger pores (about 56.47%).

A Mini Review of the State-of-the-Art Development in Oil Recovery Under the Influence of Geometries in Nanoflood

The global demand for oil and petroleum products is experiencing a significant increase, while the number of newly discovered oil reservoirs is relatively low. This emphasises the critical need for innovative techniques to enhance the rate of oil recovery in order to meet global demand. The implementation of nanotechnology in enhanced oil recovery (EOR) yields numerous advantages, including cost savings in production and improved oil recovery. Additionally, it is critical to investigate the geometrical behaviour of the reservoir, as this information is vital for determining the maximum oil recovery rate. This review highlights the significance of nanotechnology through the utilisation of various geometries to determine the rate of hydrocarbon recovery. Furthermore, this paper also addresses the obstacles associated with achieving maximum oil recovery and provides suggestions for future research in this field. The review concludes with its key finding, which indicates that an examination of reservoir geometry utilising nanofluid in the presence of electromagnetic waves can significantly improve the rate of hydrocarbon recovery.

Rheological Properties of Weak Gel System Cross-Linked from Chromium Acetate and Polyacrylamide and Its Application in Enhanced Oil Recovery After Polymer Flooding for Heterogeneous Reservoir

Long-term polymer flooding exacerbates reservoir heterogeneity, intensifying intra- and inter-layer conflicts, which makes it difficult to recover the remaining oil. Therefore, further improvement in oil recovery after polymer flooding is essential. In this study, a weak gel system was successfully synthesized, and possesses a distinct network structure that becomes more compact as the concentration of partially hydrolyzed polyacrylamide increases. The network structure of the weak gel system provides excellent shear resistance, with its apparent viscosity significantly higher than that of partially hydrolyzed polyacrylamide solution. The weak gel system exhibits typical pseudo-plastic behavior, which is a non-Newtonian fluid as well as a viscoelastic fluid. Additionally, the weak gel system’s elasticities exceed its viscosities, and longer crosslinking time further enhances the viscoelasticity. The weak gel system achieves superior conformance control and enhanced oil recovery in highly heterogeneous reservoirs compared to partially hydrolyzed polyacrylamide solutions. The weak gel system is more suited to low-permeability reservoirs with strong heterogeneity, as its effectiveness in conformance control and oil recovery increases with greater reservoir heterogeneity. Enhanced oil recoveries of the weak gel system in low-permeability sandpacks increase from 22% to 48% with a rise in permeability ratios from 14.39 to 35.64 after polymer flooding.

Complex phase behaviours related to gas injection in reservoir fluids

Enhanced oil recovery (EOR) involves several techniques, including the injection of gas (such as natural gas, nitrogen, or CO2) into the reservoir to increase its pressure, thereby displacing oil from one or more injection wells to production wells. For this process to be effective, it is essential that the injected gas and the oil reach a homogeneous state. Particularly, the First-Contact Minimum Miscibility Pressure (FC-MMP) offers a reliable (and safe) initial estimate for the pressure at which the EOR process should be conducted. In this work, an efficient algorithm is developed that allows computing complete pressure(P)-α diagrams (α: percentage of injected gas) at a fixed temperature using traditional cubic equations of state (EoS), including complex cases with three-phase regions. This algorithm is used to study both the qualitative and quantitative behaviour of the P-α diagrams and to analyse how FC-MMP changes with the injection of different gases or gas mixtures. Various reservoir fluids from the literature (with and without asphaltenes and with varying levels of CO2 and methane) are evaluated. In one section, three injection gases are used: CO2, N2, and a synthetic natural gas mixture, comparing their effects on the P-α diagrams. Then, the impact of interaction parameters on phase equilibrium and FC-MMP is analysed, and the role of asphaltene precipitation is discussed. The study concludes with a quantitative comparison between the FC-MMP calculated here and the Multiple-Contact MMP (MC-MMP) reported for the same fluids. Additionally, the problem of whether asphaltenes precipitation should be considered or ignored in the determination of the FC-MMP is analysed and discussed, with different perspectives for conventional and non-conventional shale type reservoirs.

Damage mechanism analysis of polymer gel to petroleum reservoirs and development of new protective methods based on NMR technique

Polymer gels are widely used in water control and enhanced oil recovery in oil fields. However, the damage mechanism of polymer gels to layers with remaining oil and not requiring plugging and corresponding protective measures are unclear. In this paper, we investigated polymer gels' damage and protection performance through static gel-breaking experiments and dynamic plugging and oil recovery evaluations on rock cores. Moreover, nuclear magnetic resonance (NMR) technology was combined to analyze the damage performance of polymer gels on cores from the pore scale. In addition, a protective technique based on gel breakers for layers with remaining oil and not requiring plugging was proposed. Results showed that when polymer gels were injected into heterogeneous cores, they plugged high-permeability layers while also penetrating low-permeability layers. When the damage to the low-permeability layers was not alleviated, the conformance and oil displacement efficiency were significantly reduced. When the concentration of ammonium persulfate was 2%–5%, the gel-breaking time was shortest and the residue was very minimal. Ammonium persulfate could be used as a gel breaker and reservoir protective material. Furthermore, after injecting ammonium persulfate into heterogeneous reservoir cores, the gel damage on the face of low-permeability layers was relieved. Consequently, the improvement in sweep efficiency was achieved, showing the re-activation of the remaining oil in medium-low permeability layers. Therefore, the low-permeability layer protection process and core experiment study based on gel-breaking agents proposed in this study were suggested to provide a new technique for the field application of conformance modification agents, aiming to achieve higher recovery degrees.

Role of the process conditions on three-dimensional viscous fingering: Impact on enhanced oil recovery and geological storage

Role of the process conditions on three-dimensional viscous fingering: Impact on enhanced oil recovery and geological storage

Formulation and Characterisation of Polymer and Nanoparticle-Stabilized Anionic Surfactant Foam for Application in Enhanced Oil Recovery

Formulation and Characterisation of Polymer and Nanoparticle-Stabilized Anionic Surfactant Foam for Application in Enhanced Oil Recovery

Introducing PyFaultSlip: A free and open-source tool for the assessment of induced fault slip hazards from deep fluid injection

Induced fault slip is a significant hazard incurred by deep fluid injection operations and is inferred to be the source of recent elevated seismicity in the U.S. midcontinent. Deep fluid injection is commonly used for disposal of wastewater associated with oil and gas development and other industrial activities, enhanced oil recovery (EOR), and carbon capture and storage (CCS). However, easy-to-use tools to investigate hazards associated with disposal are lacking. Here, we present pyFaultSlip, a modular, free, and open-source tool written in Python to assess the likelihood of induced fault slip, using both 2D and 3D mapped geometries. We adopt two different approaches to assessing fault slip tendency, a ‘deterministic’ model that does not consider input uncertainty, and a ‘probabilistic’ model that uses a Monte Carlo approach to assess uncertainty. We show examples using 2D and 3D fault data in Oklahoma and Kansas. This tool is geared towards providing straightforward results that can directly communicate the likelihood of induced slip occurring on specific faults to researchers, operators, regulators, and other stakeholders of deep fluid injection projects.

Dimensionless analysis of foam stability for application in enhanced oil recovery

The stability of foam during injection into oil reservoirs is critical, especially under high-temperature and high-salinity conditions. This study formulates foam stabilizers using one polymer, two surfactants, and six types of nanoparticles (NPs). Foam stability was assessed with a static setup, examining factors such as interfacial tension (IFT), bubble characteristics, and solution viscosity through dimensionless numbers: Bond number (Bo), Worthington number (We), and Neumann number (Ne). A new formula for dimensionless electrical conductivity was also introduced. Results showed that at optimal concentrations of the four additives, foam stability improved with NPs due to enhanced surface charge from in situ physiochemical reactions, promoting their migration to the fluid interface. Notably, Ne proved more effective than Bo and We in describing foam stability as it accounts for droplet height’s impact on IFT. Acidic NPs demonstrated greater electrostatic force than amphoteric NPs, correlating with improved foam stability reflected in a downward trend in the Ne plot. Additionally, we analyzed the coarsening rate of foam bubbles over time and its relationship to stability. Our findings suggest that dimensionless numbers serve as valuable benchmarks for evaluating foam stability across various additive mechanisms.

Natural Gas Liquid Huff ’n’ Puff in Ultratight Shale Reservoirs: An Experimental and Modeling Study

Summary Solvent huff ’n’ puff (HnP) is becoming a common enhanced oil recovery (EOR) practice in unconventional tight and ultratight reservoirs. For an effective HnP operation, achieving miscibility is essential for promoting solvent transport into the reservoir matrix and subsequent oil production. This is typically achieved by either increasing the injection pressure or enriching the solvent. However, injection pressure is constrained by compressor capacity, formation fracture pressure, and lateral/vertical containment. In this study, we experimentally assess the feasibility of using natural gas liquid (NGL) for HnP in an ultratight Eagle Ford (EF) shale sample, providing insights into extreme solvent enrichment scenarios in an HnP process. We hypothesize that NGL extracts oil from an oil-saturated shale core through a counterdiffusion process, primarily governed by first-contact miscibility (FCM) between NGL and oil. In this study, we explore the impact of solvent injection on the phase envelope of both dead oil and live oil during the HnP process. We present a critical comparison between C1 HnP, representing the lower limit of solvent enrichment, and NGL HnP, representing the upper limit, focusing on their respective oil recovery mechanisms and in-situ solvent-oil interactions. Using a high-pressure and high-temperature (HPHT) visualization apparatus, we investigate the interactions between NGL and oil, as well as their compositional variations, under bulk-phase conditions and in the core during the HnP process. We propose an analytical theory for the transport of NGL and oil into and out of an ultratight porous medium, explaining the experimental oil recoveries observed from the shale core. NGL and oil transport is modeled under a diffusion-dominated scenario, with FCM playing a crucial role in enhancing diffusion. Compositional analysis indicates that, contrary to C1, NGL extracts heavier oil components during the soaking stage. Core visualization demonstrates a gradual color change of NGL from clear to amber during soaking, indicating oil production via counterdiffusion. NGL expands the two-phase envelope of the dead oil, making it more volatile, while suppressing the phase envelope of the live oil. This potentially extends the duration of single-phase oil flow during the depletion stage in a live-oil system and enhances the oil production through diffusion. NGL achieves significantly lower FCM pressure (FCMP) with oil compared with C1, C1/C2 (70/30), C2, and separator gas, explaining its higher diffusion into the oil-saturated core. The analytical model demonstrates that NGL diffuses to the end of the core by the end of soaking. NGL recovers significantly more oil than C1 in the HnP process. Most of the oil is produced during soaking due to counterdiffusion, with solution-gas drive contributing additional recovery at later stages of depletion, though not as markedly as in C1 HnP.