Thermal Recovery Methods Research Articles

Multiphysics Field Coupled to a Numerical Simulation Study on Heavy Oil Reservoir Development via Electromagnetic Heating in a SAGD-like Process

Conventional thermal recovery methods for heavy oil suffer from significant issues such as high water consumption, excessive greenhouse gas emissions, and substantial heat losses. In contrast, electromagnetic heating, as a waterless method for heavy oil recovery, offers numerous advantages, including high thermal energy utilization, reduced carbon emissions, and volumetric heating of the reservoir, making it a focus of recent research in heavy oil thermal recovery technologies. This paper presents a numerical simulation study of electromagnetic heating for heavy oil recovery, using a heavy oil block in the Bohai Bay oilfield in China as a case study. Firstly, a multiphysics field coupled to a mathematical model was established, considering the impact of the temperature on the heavy oil viscosity, the threshold pressure gradient of non-Darcy flow, and the dielectric properties of the reservoir, along with heat dissipation from overlying and undercover sandstone and gravitational effects on fluid flow. Secondly, a numerical simulation method for the coupled multiphysics fields was developed, and the convergence and stability of the numerical simulation method were tested. Finally, a sensitivity analysis based on the numerical simulation results identified the factors affecting heavy oil production. It was found that electromagnetic heating significantly enhances heavy oil production, and the threshold pressure gradient greatly influences the prediction of heavy oil production. Moreover, heat dissipation from the overlying and undercover sandstone severely reduces cumulative oil production. When the production well is located below the electromagnetic heating antenna, larger well spacing results in higher cumulative heavy oil production. Higher heavy oil production is achieved when the antenna is positioned at the center of the reservoir for the studied cases. Power has a big effect on increasing heavy oil production, but its influence diminishes as power increases. There exists an optimal range of electromagnetic frequencies for maximum cumulative production, and higher water saturation leads to poorer electromagnetic heating efficiency. This study provides a theoretical foundation and technical support for the numerical simulation technology and development plan optimization of heavy oil reservoirs subjected to electromagnetic heating.

Technology Progress in High-Frequency Electromagnetic In Situ Thermal Recovery of Heavy Oil and Its Prospects in Low-Carbon Situations

Heavy oil resources are abundant globally, holding immense development potential. However, conventional thermal recovery methods such as steam injection are plagued by high heat loss, substantial carbon emissions, and significant water consumption, making them incompatible with carbon reduction goals and the sustainable socioeconomic development demands. A new method of high-frequency electromagnetic in situ heating, which targets polar molecules, can convert electromagnetic energy into heat so as to achieve rapid volumetric heating of the reservoir. This method has the potential to overcome the drawbacks of traditional techniques. Nevertheless, it faces significant drawbacks such as limited heating range and inadequate energy supply during later production stages, which necessitates auxiliary enhancement measures. Various enhancement measures have been reported, including nitrogen injection, hydrocarbon solvent injection, or the use of nano-metal oxide injections. These methods are hindered by issues such as pure nitrogen being easy to breakthrough, high costs, and metal pollution. Through extensive literature review, this article charts the evolution of high-frequency electromagnetic in situ heating technology for heavy oil and the current understanding of the coupled heat and mass transfer mechanisms underlying this technology. Moreover, based on a profound analysis of the technology’s progression trends, this work introduces a new direction: CO2-N2 co-injection as an enhancement strategy for high-frequency electromagnetic in situ heavy oil recovery. There is promising potential for the development of new technologies in the future that combine high efficiency, low carbon emissions, environmental friendliness, economic viability, and energy conservation. Furthermore, some research prospects in low-carbon situations and challenges for the new technology in future are presented in detail. All in all, the contribution of the paper lies in the summarizing of some main drawbacks of current enhanced electromagnetic in situ thermal recovery methods, and presents a novel research direction of using CO2-N2 co-injection as an enhancement strategy based on its current research status in low-carbon situations.

Analysis of Adaptability and Application Potential of Supercritical Multi-Source Multi-Component Thermal Fluid Technology for Offshore Heavy Oil in China

Supercritical multi-source, multi-component thermal fluid is a heavy oil thermal recovery method independently developed by China National Offshore Oil Co., Ltd (Beijing, China). It uses waste liquid at the production end of the production well as the water source, the injection medium temperature exceeds 374 °C, 22.1 MPa, and all the produced flue gas is re-injected. Compared with steam huff and puff technology, supercritical technology has the advantages of high enthalpy value, high heat utilization rate, good oil displacement effect, and being green and pollution-free. In addition, its oil–water treatment cost is low, it can realize the reuse of organic matter, it has a good cost advantage of water treatment under the background of low carbon, and it is a thermal recovery method with great application potential for offshore heavy oil. Therefore, it is necessary to carry out research on the adaptability and application potential of supercritical multi-source, multi-heat flow thermal recovery technology in the sea. Based on the laboratory one-dimensional displacement experiment, this paper reveals the mechanism of heavy oil supercritical multi-source multi-component thermal fluid displacement and the contribution of supercritical components to the displacement effect, and establishes the supercritical multi-source, multi-component thermal fluid numerical simulation characterization method. Combined with the characteristics of offshore heavy oil reserves, the main control factors affecting supercritical multi-source, multi-component thermal fluid development were established by numerical simulation and orthogonal test methods, and the adaptive screening method of offshore supercritical technology was established. The application potential of 670 million tons of offshore heavy oil reserves was evaluated and sorted, and KL 10-2 oilfield was selected as the pilot test oilfield. The results show that supercritical technology has great advantages in oil displacement and water treatment cost reduction, and the results play an important guiding significance for the development of offshore heavy oil technology system and the iteration of new technology.

Defining the Ideal Range for Reducing Oil Viscosity and the Optimal Rate of Steam Injection for a Heavy Oil Field

Heavy oil reservoirs often lend themselves well to thermal enhanced recovery techniques. Traditional methods like primary production or water injection are less effective due to the high viscosity of the oil. Steam stimulation primarily aims to elevate the reservoir's temperature, thereby reducing the oil's viscosity and improving its flow properties. Steam injection stands as one of the most prevalent thermal recovery methods, commonly applied in heavy oil reservoirs. The primary goal is to validate the process for selecting suitable reservoirs, the physical mechanisms involved, and the simulation characteristics essential for steam recovery. This study establishes the optimal multiplier for reducing oil viscosity and the ideal steam injection rate for heavy oil fields.

Pre-extraction of Li from spent lithium-ion batteries through an Ethanol-Water vapor thermal reduction approach

Pre-extraction of lithium from spent lithium-ion batteries (LIBs) is highly required to obtain a high recovery rate of lithium. Here, we report an ethanol–water vapor thermal reduction approach in a sealed reactor to selectively recycle lithium and transition metal oxides (TMOs) from spent LIBs. Spent cathode materials were converted to LiOH and TMO by the reduction of water-alcohol vapor at a temperature of 350–400 °C. More than 99 % of the Li in LiCoO2 was selectively extracted from LiCoO2 at 370 °C for 2 h and at 400 °C for 0.8 h. The selective extraction is co-driven by water and alcohol that enable the reduction of LiCoO2 and release water-soluble LiOH and water-insoluble TMOs. In addition, the water–vapor thermal reduction method is applicable to selectively recovery Li from different types of cathode materials such as NCMs and lithium manganese oxide. The pre-selective extraction ensures a high lithium recovery rate and a reagent-saving manner. We envision that the vapor thermal recovery method could help recycle spent LIBs by an environmentally friendly and economically reasonable way.

An accelerated computational platform for optimal field developments with reduced footprint

Reducing the environmental footprint and increasing efficiency of hydrocarbon production as well as geological sequestration of carbon dioxide (CO2) through optimally selected and operated fewer wells is crucial for cleaner and more sustainable energy transition. We describe a parallel subsurface field-development optimization (SFDO) platform with novel components. SFDO enables the optimization of well-locations/-trajectories (WLO), controls (WCO), and both jointly (WLO–WCO). All objective function computations are performed in parallel at a given iteration in SFDO.The novel distributed quasi-Newton (DQN) optimizer is an important new element in accelerating SFDO. DQN is developed using a multi-threaded optimization paradigm that utilizes high-performance computing (HPC) to distribute an ensemble of optimization threads. By operating its threads in parallel within a single optimization run, DQN efficiently identifies multiple distinct local optima of the objective function. DQN tracks and updates a common input-output (training) data set by recording the responses from successful simulation runs. The support-vector regression (SVR) method is used to approximate the Hessian matrix while objective function gradients are estimated analytically using SVR-computed sensitivities.The DQN implementation inside SFDO is extensively tested and validated in this work. We first validate DQN using a synthetic test case with a pre-computed solution. DQN incurs fewest number of simulations, and thus, the shortest run time while successfully finding the global optimum. For the first time in the literature, we show that DQN is more effective than alternative methods in problems involving WCO and WLO–WCO. Then, we report on DQN's performance against alternative techniques in four realistic applications, namely on a WLO problem for environmental footprint reduction and a novel WLO–WCO application for the geological sequestration of CO2 involving a novel take on WLO with deforming well trajectories. Finally, we describe two realistic WLO problems in which the well count is also optimized in addition to the well locations. One of these applications is for heater-well pattern optimization for an innovative unconventional thermal recovery method. DQN finds local optima by incurring a significantly lower computational cost in comparison to alternative methods. Results of the field tests support the advantageous qualities of DQN previously observed in synthetic tests. We conclude that SFDO accelerated with DQN helps increase the efficiency and reduce the footprint of realistic field-scale developments.

The main features of compositional modeling algorithms of modern reservoir flow simulators

Modern industrial reservoir flow simulators are integrated software products consisting of several packages. Modeling of gas injection with various compositions, or hydrocarbon recovery from gas-condensate and oil-gas-condensate reservoirs, or thermal recovery methods requires a detailed account for composition of the fluid system. In these cases, compositional (multi-component) flow simulation is used to calculate component distribution between the coexisting phases, the number and the fractions of the phases, together with the flow equations for fluid components.. For this purpose, the flow simulator solves the thermodynamic subproblem using basic methods and algorithms analogous to the fluid modeling (PVT modeling) packages. The paper describes the main principles and specific features of implementation of the compositional modeling algorithms in several modern reservoir flow simulators. Keywords: compositional modeling; multicomponent flow model; reservoir flow simulator; isothermal and non-isothermal compositional modeling.

A brief review of steam flooding and its applications in fractured oil shale reservoirs

Steam flooding is an important thermal recovery method for heavy oil reservoirs, and convective heating technology is used to fracture oil shale reservoirs with good results. This paper reviews the main prediction methods, optimization approaches for steam flooding performance, and its application in fractured oil shale reservoirs. The prediction methods include experimental, numerical simulation, and statistical models. These provide insights into steam override, heat transfer, and production dynamics. To optimize steam flooding, parameters like quality, temperature, injection rate, and allocation need to be coordinated based on reservoir conditions and monitoring data. Real-time injection control, economic analysis, and sweep efficiency improvements should also be considered in optimization workflows. Although progress has been made, more field studies are needed to establish systematic optimization practices utilizing advanced technologies. This review summarizes the key developments in steam flooding modeling and optimization, providing a reference for further research and field applications.

The Influence of Interlayer on the Development of Steam Chamber in Steam Stimulation during Heavy Oil Recovery

Cyclic steam stimulation is an effective thermal recovery method for heavy oil recovery. The key potential mechanism is the growth of the steam chamber after steam injection. Taking the LD5X heavy oil reservoir as an example, besides the interlayer developed in this area, the top water and bottom water distribute above and below the interlayer. These factors may have adverse effects on the development of the steam chamber, thus affecting the final heavy oil exploitation. In this work, our goal is to study the effects of interlayer permeability and well–interlayer distance on CSS performance (in the presence of top and bottom water). We developed a high-temperature-resistant interlayer. Based on the simulated interlayer, the field scale model was converted into a laboratory element model through the similarity criterion. In order to quantitatively evaluate the performance of steam stimulation, a thermal detector was used to measure the dynamic growth of the steam chamber and record the production data. The experimental results show that the self-made interlayer has high-temperature resistance, adjustable permeability, and little difference between the physical parameters and the target interlayer. During the cyclic steam stimulation process, the steam chamber presents two different stages in the presence of the top water area, namely the normal production stage and the top water discharge stage. The bottom water has little effect on the growth of the steam chamber. The small interlayer permeability, the increase in horizontal well–interlayer distance, and the existence of the interlayer will delay the top water leakage during steam stimulation. This study has reference significance for us to develop heavy oil resources with a top water barrier when implementing steam stimulation technology.

Change Characteristics of Heavy Oil Composition and Rock Properties after Steam Flooding in Heavy Oil Reservoirs

The thermal recovery method of steam flooding is one of the most common development methods for heavy oil reservoirs. However, after multiple rounds of steam injection development, the composition of crude oil and reservoir rock properties have changed greatly, which is unfavorable for the subsequent enhanced oil recovery. It is necessary to study the distribution of the remaining oil after the thermal recovery of heavy oil reservoirs, and clarify the change characteristics of the components of the crude oil under different steam injection conditions. At the same time, the change of porosity and the permeability of the rocks after steam flooding, and its influence on oil recovery, are investigated. In this paper, the composition changes of heavy oil before and after steam flooding are studied through experiments and numerical simulation methods. A numerical model is established to study the retention characteristics of heavy components in heavy oil reservoirs by the CMG software. The effects of different steam injection conditions, and heavy oil with different components on the residual retention of heavy components, are compared and studied. The changes of rock physical properties in heavy oil reservoirs after steam flooding is clarified. The results show that after steam flooding, the heavy components (resin and asphaltenes) of the recovered oil decrease, and the heavy components in the formation increase in varying degrees. With the increase of heavy components in the crude oil, the remaining oil in the formation increases after steam flooding, and the retention of heavy components increases; after steam flooding, the stronger the rock cementation strength, the higher the degree of reserve recovery, and it is difficult to form breakthrough channels; the greater the steam injection intensity, the earlier to see steam breakthrough in the production well, and the lower the degree of reserve recovery. The research reveals the changes of heavy oil components and rock properties after steam flooding, providing support for the subsequent enhanced oil recovery.

Understanding the Impact of Reservoir Low-Permeability Subdomains in the Steam Injection Process

Optimizing production in the mature fields of heavy oil reservoirs is still challenging. In most cases, conventional recovery techniques are not effective, although they are suitable for applying thermal recovery methods. Steam injection involves injecting steam into the reservoir where the heat exchange with the oil occurs. This promotes a reduction in oil viscosity and thus increases its mobility. One of the challenges of the EOR project is understanding how the presence of regions with contrasting properties, such as fractures, caves, and barriers, could affect the steam flow. This work investigates the impact of low-permeability barriers in the steam injection process. The barriers were created on a semi-synthetic reservoir characteristic of Brazilian onshore mature fields. We used the three-phase pseudo-compositional reservoir simulation STARS (Steam Thermal Advanced Processes Reservoir Simulation) for simulations. Our results show that the shape, number, and arrangement of barriers in a porous medium can affect the amount of oil recovered. They may also be able to anticipate or delay oil production.

STEAM INJECTION NUMERICAL ANALYSES IN HEAVY OIL RESERVOIRS

Thermal recovery methods aim to reduce oil viscosity, thus, increasing its mobility and enhancing its recovery. Reservoir numerical simulation is a powerful tool for predicting reservoir production performance under different operational parameters. One critical point is understanding the relationship between flow rate and recovery factor. This study aims to analyze steam injection into the porous medium in heavy oil reservoirs by numerical simulation using a commercial multiphase flow simulator to simulate the continuous steam injection process. The homogeneous reservoir was built with 14,375 cells. The fluid model has characteristics of onshore Northeastern Brazilian fields. Simulations were performed over a period of 16 years, and results indicate that the steam injection promotes oil production anticipation but reaches a limit as the flow rate increases. The results presented can contribute to improve the understanding of the effects of flow rate in a heavy oil reservoir.

Experimental investigation of enhanced oil recovery and in-situ upgrading of heavy oil via CO2- and N2-assisted supercritical water flooding

Exploitation of heavy oil is critical for mitigating the energy crisis. However, conventional thermal recovery methods cannot completely exploit the potential of heavy oil owing to its high viscosity and heavy distillates. A new technology is proposed with reference to CO2– and N2-assisted supercritical water (MGA-SCW) injection for heavy oil recovery. In this study, an experimental apparatus was developed to simulate the MGA-SCW flooding process and test its feasibility. MGA-SCW injection remarkably enhanced oil recovery, increased the oil production rate, and improved the oil quality. For MGA-SCW flooding at 25 MPa and 400 °C, the recovery factor approached 95 %, and the oil viscosity decreased by 32 %; the light distillate fraction (180–350 °C) increased from 11 to 15 %. The dynamic process of MGA-SCW flooding is divided into three stages: pressure difference, thermal, and miscible drives. This technology can be applied to the development and utilization of offshore heavy oil fields.

Gas production from marine gas hydrate reservoirs using geothermal-assisted depressurization method

Natural gas production from marine gas hydrate reservoirs has become attractive to the oil and gas industry in recent years. It is still a great challenge to recover natural gas from hydrate reservoirs efficiently mainly due to sand production and wellbore collapse problems associated with the production scheme of depressurization. The thermal recovery method has not been proven economical due to the high cost of energy consumption. This study focuses on using geothermal energy to assist the depressurization process so that well pressure drawdown can be reduced and thus sand production and wellbore collapse problems can be mitigated. The authors investigated the transfer of heat energy from a natural geothermal zone to a marine gas hydrate reservoir and its effect on gas well productivity using analytical models. The result of our investigation shows that the initial well productivity can be significantly improved using geothermal energy more than 10-fold. This work provides engineers with an analytical tool for the feasibility analysis of using geothermal energy to improve well performance in gas hydrate reservoirs. Cited as: Mahmood, M. N., Guo, B. Gas production from marine gas hydrate reservoirs using geothermal-assisted depressurization method. Advances in Geo-Energy Research, 2023, 7(2): 90-98. https://doi.org/10.46690/ager.2023.02.03

Asphaltene Behavior during Thermal Recovery: A Molecular Study Based on Realistic Structures

Asphaltene precipitation and deposition can occur at both the surface and subsurface levels, leading to the formation of organic-based scales. Asphaltene precipitation can also lead to changes in petrophysical properties such as wettability, which affects the ultimate recovery. Asphaltene precipitation is linked to changes in fluid composition driven by pressure drawdown and temperature variation across the reservoir. Thus, asphaltene deposition can adversely influence the ultimate recovery. Thermal recovery methods are invoked to mitigate the adverse effects of asphaltene precipitation. The behavior of asphaltene under thermal recovery along with the link between the asphaltene molecular structure and its response to the increase in temperature during thermal recovery are not fully understood. In this paper, realistic asphaltene structures based on actual crude samples were recreated on a computational platform, and several characteristics of the asphaltene structures (density, viscosity, and interfacial tension) were evaluated during the heating process. The density of asphaltene was correlated with the percentage of aromatic carbon in its structure. The viscosity and interfacial tension decreased substantially as the temperature increased. The IFT reduced by approximately 30 mN/m as the temperature was increased from 300 K to 450 K. Moreover, the mechanical stability of asphaltene was found to be highly influenced by heating. The findings provide nanoscale insights into the behavior of asphaltene during thermal recovery, which can be used to improve the design of thermal recovery processes.

The effect of bitumen molecular fractions on diffusivity and rheology of bitumen under high‐temperature conditions: Molecular dynamics (MD) simulation study

AbstractHeavy oil and bitumen play an incredible role in Canada's energy resources. The main processes that have already been applied to produce heavy oil and bitumen are in‐situ thermal methods. The primary mechanism of production in these reservoirs is a reduction in heavy oil and bitumen viscosities via heat transfer. Having deep knowledge about the rheological behaviour of heavy oil and bitumen is crucial to designing a more accurate and efficient in‐situ thermal recovery method. In this work, molecular dynamics (MD) simulation was used to model the rheological behaviour of bitumen under different temperatures. According to MD outputs, the highest diffusion coefficient between bitumen fractions belongs to saturate fractions. On the other hand, the lowest diffusion coefficient belongs to asphaltene fractions. The size of asphaltene, its polarity, and the polarity of a resin fraction affect the diffusion coefficient of asphaltene in a bitumen sample and its rheological behaviour. The MD simulation aims to provide molecular insights and essential information about the rheological trend of bitumen under different thermodynamic conditions. The results of the current work provide essential information about the effect of bitumen fractions on its rheological behaviour.

Analytic dependencies used to study temperature profile in high-viscosity reservoirs with underlying contact water zone developed by thermal recovery methods

Analytic dependencies used to study temperature profile in high-viscosity reservoirs with underlying contact water zone developed by thermal recovery methods

Insights into enhanced oil recovery by thermochemical fluid flooding for ultra-heavy reservoirs: An experimental study

The thermal recovery method (especially for steam injection) is widely used for heavy oil recovery due to the high viscosity and poor fluidity of heavy oil. In this paper, a thermochemical fluid flooding is proposed for ultra-heavy oil reservoirs. The different thermochemical fluid flooding methods are compared, and the best flooding method is suggested. The synergistic effect of thermochemical fluid on oil viscosity is investigated, and the injection parameter optimization is selected. Finally, the feasibility of multi-stage viscosity reduction is discussed, and a suitable experimental scheme is also proposed. The results show that DCS (viscosity reducer (D) + CO2 (C) + steam (S)) flooding exhibits the highest oil recovery (about 70.3 %). The thermal viscosity reduction by steam decreases the oil viscosity, which is helpful for CO2 and viscosity reducer diffusion. Besides, the enhanced CO2 diffusion can also reduce oil viscosity and facilitate viscosity reducer diffusion. Therefore, viscosity reducer, CO2, and steam have a synergistic effect on oil viscosity reduction. The average oil recovery increases rapidly with the CO2 volume and then slows down, which is similar to that of viscosity reducer. The inflection points for CO2 and viscosity reducer appear at 0.20 PV (pore volume) and a concentration of 2.0 %, respectively. The optimal injection parameters for DCS flooding are 2.0 % of viscosity reducer + 0.20 PV CO2 + 2.5 PV steam. The multi-stage viscosity reduction is feasible for thermochemical fluid flooding due to the prolonged effective action time of the viscosity reducer. The CO2 multiple stages injection has less impact on the oil recovery (a difference of 1.08 %). The DCSDS (viscosity reducer + CO2 + steam + viscosity reducer + steam) flooding is recommended from the perspective of cost reduction.

Methods to Enhance Success of Field Application of In-Situ Combustion for Heavy Oil Recovery

Summary While much has been learned in the laboratory over the past four decades about the in-situ combustion (ISC) process, especially through carefully conducted physical model experiments, and many advancements in numerical simulation capability have been achieved, successful field application of ISC remains a rarity. This paper discusses challenges that have been faced in moving from laboratory to field and some strategies that may be used for improving the success rate. There is a brief discussion of the advantages and disadvantages of ISC as a recovery method and comparisons with steam injection, which is the dominant thermal recovery method used in the field. A discussion of the challenges and progress made in numerical simulation is provided with the suggestion that such mathematical modeling can now be a useful tool in designing field projects and can increase the probability of success. The needs of industry to operate safe, simple, and economically and environmentally sustainable projects are discussed along with the currently negative perception of the ISC process in industry. The paper makes some suggestions regarding how to address these issues. The main thesis of this paper is that air injection into a reservoir introduces a large amount of nitrogen that is detrimental to the displacement of oil, and oil recovery yet offers few, if any, advantages. Reducing the amount of noncondensable gas (NCG) associated with the process can be done mainly in two ways—by using oxygen-enriched air injection and furthermore by injecting a mixture of steam and oxygen-enriched air. The paper does not make a comprehensive review of past field projects but does include a summary of promising areas for future application of the ISC combustion recovery process.

Experimental study on the feasibility of nitrogen huff-n-puff in a heavy oil reservoir

Heavy oil reservoirs are much more challenging to be exploited by water flooding than conventional oil reservoirs because of high viscosity. However, gas injection has advantages such as viscosity reduction, oil swelling, extraction, and interfacial tension reduction. Furthermore, it is more economical than thermal recovery methods. Previous pressure depletion testing has proved that nitrogen(N2) can form a foamy oil flow in the solution gas drive stage. In addition, crude oil has sufficient mobility under high-temperature conditions in relatively deep, heavy oil reservoirs. In this study, the feasibility of N2 huff-n-puff in heavy oil reservoirs was determined by observing the flow behavior and oil recovery factor through huff-n-puff tests in a two-dimensional planar model and a real-time, high-pressure visual cell. Stable foamy oil flow can be formed, and the overall recovery can reach 35.73 % when the pressure depletion rate was 16 kPa/min. The advantage of nitrogen huff-n-puff is high early production, and the application of nitrogen huff-n-puff in the early stage is not only low in cost but also highly efficient in production. Nitrogen huff-n-puff forms some large-contact-area gas chambers that can enhance the effect of using other high-cost solvents in the later stage. The results of this study can provide some theoretical basis and technical guidance for the application of nitrogen huff-n-puff in relatively deep, heavy oil reservoirs.