Search Results (85)

A comprehensive study on the distribution characteristics and exploitation strategies of remaining oil was carried out in the Ordovician ultra-deep fault-controlled fractured–vuggy carbonate reservoir within the Shunbei No. 1 strike–slip fault zone. This research addresses challenges such as severe watered-out and gas channeling encountered during multi-stage development, marking a shift toward a development phase focused on residual oil recovery. By integrating seismic attributes, drilling, logging, and production performance data—and building upon previous methodologies of “hierarchical constraint and genetic modeling”—a three-dimensional geological model was constructed with a five-tiered architecture: strike–slip fault affected zone, fault-controlled unit, cave-like structure, cluster fillings, and fracture zone. Numerical simulations were subsequently performed based on this model. The results demonstrate that the distribution of remaining oil is dominantly controlled by the coupling between key geological factors—including fault kinematics, reservoir architecture formed by karst evolution, and fracture–vug connectivity—and the injection–production well pattern. Three major categories with five sub-types of residual oil distribution patterns were identified: (1) local low permeability, weak hydrodynamics; (2) shielded connectivity pathways; and (3) Well Pattern-Dependent. Accordingly, two types of potential-tapping measures are proposed: improve well control through optimized well placement and sidetrack drilling and reservoir flow field modification via adjusted injection–production parameters and sealing of high-permeability channels. Techniques such as gas (nitrogen) huff-and-puff, gravity-assisted segregation, and injection–production pattern restructuring are recommended to improve reserve control and sweep efficiency, thereby increasing ultimate recovery. This study provides valuable guidance for the efficient development of similar ultra-deep fractured–vuggy carbonate reservoirs. Full article

Ammonia (NH₃) is a zero-carbon fuel and an attractive hydrogen (H₂) carrier for gas turbine power generation due to its high energy density, ease of storage, and transportation. This study numerically investigates NH₃/air combustion using a hybrid Well-Stirred Reactor (WSR) and Plug Flow Reactor (PFR) model in Cantera at pressures of 1–20 atm, temperatures of 1850–2150 K, and equivalence ratios (ϕ) of 0.7–1.2. The effects of pressure, equivalence ratio, and temperature on NH₃ conversion and NO formation are examined. Results show that NH₃ exhibits a non-monotonic conversion curve with pressure after the WSR, reaching a minimum near 5 atm, whereas NO formation decreases monotonically from 1 to 20 atm. Equivalence ratio sweeps show that NO decreases steeply as ϕ increases from 0.7 to ~1.1 as nitrogen is redirected toward N₂ and oxidizer availability declines; residual NH₃ increases rapidly for ϕ > 1.0, especially at high pressure. Increasing temperature accelerates NH₃ oxidation and raises NO formation, most strongly at low pressure where thermal and NH/OH pathways are least inhibited. These results indicate that co-tuning pressure and equivalence ratio near rich operation enables low-NO_x ammonia combustion suitable for advanced gas turbine applications. Full article

Supercritical CO₂ modifies deep coal reservoirs through the coupled effects of adsorption-induced deformation and geochemical dissolution. CO₂ adsorption causes coal matrix swelling and facilitates micro-fracture propagation, while CO₂–water reactions generate weakly acidic fluids that dissolve minerals such as calcite and kaolinite. These synergistic processes remove pore fillings, enlarge flow channels, and generate new dissolution pores, thereby increasing the total pore volume while making the pore–fracture network more heterogeneous and structurally complex. Such reservoir restructuring provides the intrinsic basis for CO₂ injectivity and subsequent CH₄ displacement. Both adsorption capacity and volumetric strain exhibit Langmuir-type growth characteristics, and permeability evolution follows a three-stage pattern—rapid decline, slow attenuation, and gradual rebound. A negative exponential relationship between permeability and volumetric strain reveals the competing roles of adsorption swelling, mineral dissolution, and stress redistribution. Swelling dominates early permeability reduction at low pressures, whereas fracture reactivation and dissolution progressively alleviate flow blockage at higher pressures, enabling partial permeability recovery. Injection pressure is identified as the key parameter governing CO₂ migration, permeability evolution, sweep efficiency, and the CO₂-ECBM enhancement effect. Higher pressures accelerate CO₂ adsorption, diffusion, and sweep expansion, strengthening competitive adsorption and improving methane recovery and CO₂ storage. However, excessively high pressures enlarge the permeability-reduction zone and may induce formation instability, while insufficient pressures restrict the effective sweep volume. An optimal injection-pressure window is therefore essential to balance injectivity, sweep performance, and long-term storage integrity. Importantly, the enhanced methane production and permanent CO₂ storage achieved in this study contribute directly to greenhouse gas reduction and improved sustainability of subsurface energy systems. The multi-field coupling insights also support the development of low-carbon, environmentally responsible CO₂-ECBM strategies aligned with global sustainable energy and climate-mitigation goals. The integrated experimental–numerical framework provides quantitative insight into the coupled adsorption–deformation–flow–geochemistry processes in deep coal seams. These findings form a scientific basis for designing safe and efficient CO₂-ECBM injection strategies and support future demonstration projects in heterogeneous deep coal reservoirs. Full article

To address the problem of serious gas channeling during CO₂ flooding in low-permeability reservoirs, which leads to poor oil recovery, this study developed a CO₂-resistant gel using a novel CO₂-responsive polymer (ADA) for gas channel control. The ADA polymer was synthesized via free-radical copolymerization of acrylamide (AM), dimethylaminopropyl methacrylamide (DMAPMA), and 2-acrylamido-2-methylpropanesulfonic acid (AMPS), which introduced protonatable tertiary-amine groups and sulfonate moieties into the polymer backbone. Comprehensive characterizations confirmed the designed structure and adequate thermal stability of the ADA polymer. Rheological tests demonstrated that the ADA polymer solution exhibits significant CO₂-triggered viscosity enhancement and excellent shear resistance. When crosslinked with phenolic resin, the resulting ADA gel showed outstanding CO₂ tolerance under simulated reservoir conditions (110 °C, 10 MPa). After 600 s of CO₂ exposure, the ADA gel retained over 99% of its initial viscosity, whereas a conventional HPAM-based industrial gel degraded to 61% of its original viscosity. The CO₂-resistance mechanism involves protonation of tertiary amines to form quaternary ammonium salts, which electrostatically interact with sulfonate groups, creating a reinforced dual-crosslinked network that effectively protects the gel from H⁺ ion attack. Core flooding experiments confirmed its ability to enhance oil recovery by plugging high-permeability channels and diverting flow, achieving a final recovery of up to 48.5% in heterogeneous cores. This work provides a novel gel system for improving sweep efficiency and storage security during CO₂ flooding in low-permeability reservoirs. Full article

Water Alternating Gas (WAG) injection is a well-established enhanced oil recovery technique that improves sweep efficiency by combining the favorable displacement characteristics of waterflooding and gas injection. This work presents a sequential Picard–Newton formulation for simulating three-phase flow under WAG conditions in heterogeneous petroleum reservoirs. The mathematical model addresses slightly compressible, immiscible oil, water, and gas phases under constant-temperature conditions, with the governing equations discretized in space and time using the finite volume method. Reservoir heterogeneity is represented through geostatistical permeability fields generated by Sequential Gaussian Simulation, capturing the spatial correlations and anisotropy characteristic of subsurface formations. The methodology is applied to investigate WAG performance in heterogeneous reservoir models with mean permeabilities of 100, 200, and 400 × 10⁻¹⁵ m² under identical 1:1 injection ratios. The numerical results successfully reproduce the cyclic saturation and production behavior characteristic of WAG processes. Comparative analysis reveals that higher permeability enhances injectivity and cumulative recovery but accelerates gas breakthrough and, in the highest-permeability case, water breakthrough, as well as production decline, illustrating the trade-off between displacement efficiency and sweep control. These findings demonstrate that the proposed framework provides an efficient and physically consistent tool for evaluating WAG strategies in heterogeneous reservoirs, with potential application to field-scale optimization of advanced recovery operations. Full article

Fractured-vuggy carbonate reservoirs primarily have pores and caves as their main storage spaces with poor fracture development, resulting in low reservoir connectivity and strong heterogeneity. During nitrogen injection developments, the fluidity of the medium is poor, and gas tends to form dominant flow channels, leading to a short response time. Consequently, the displacement of crude oil in such reservoirs is limited, leaving a large proportion of residual oil trapped within the pore and vug systems. Based on the Tarim fractured-vuggy carbonate reservoir, a two-dimensional visualized physical model of the fractured-vuggy body was designed and constructed to conduct a foam-assisted gas displacement physical experiment. The research shows that foam has good oil recovery efficiency and dominant channel-blocking ability, which can effectively mobilize the residual oil in the fractures and vugs after gas displacement. In the vertical direction, the foam-assisted gas flooding mechanism primarily involves gravity segregation and interfacial tension reduction between oil and water; horizontally, it operates by selectively blocking large fractures and main channels, redirecting gas into smaller and more tortuous pathways, thus enhancing overall sweep efficiency. Once dominant flow channels develop, injecting salt-sensitive foam at a 2:1 gas–liquid ratio and 0.3 pore volume can raise the recovery factor from around 3% to nearly 19%, representing an improvement of about 16%, thereby boosting both gas flooding performance and overall field development efficiency. Full article

At present, most oilfields in China have entered the late, high-water-cut stage, commonly facing declining single-well productivity and increasingly pronounced reservoir heterogeneity. Prolonged waterflooding has further exacerbated permeability contrast, yielding complex, hard-to-produce residual-oil distributions. Accordingly, the development of efficient enhanced oil recovery (EOR) technologies has become a strategic priority and an urgent research focus in oil and gas field development. Weak gels, typical non-Newtonian fluids, exhibit both viscous and elastic responses, and their distinctive rheology shows broad application potential for crude oil extraction in porous media. Targeting medium–high-permeability reservoirs with high water cut, this study optimized and evaluated a weak gel system. Experimental results demonstrate that the optimized weak gel system achieves remarkable oil displacement performance. The one-dimensional dual-sandpack flooding tests yielded a total recovery of 72.26%, with the weak gel flooding stage contributing an incremental recovery of 14.52%. In the physical three-dimensional model experiments, the total recovery reached 46.12%, of which the weak gel flooding phase accounted for 16.36%. Through one-dimensional sandpack flow experiments and three-dimensional physical model simulations, the oil displacement mechanisms and synergistic effects of the optimized system in heterogeneous reservoirs were systematically elucidated from macro to micro scales. The optimized system demonstrates integrated synergistic performance during flooding, effectively combining mobility control, displacement, and oil-washing mechanisms. Macroscopically, it effectively strips residual oil in high-permeability zones via viscosity enhancement and viscoelastic effects, efficiently blocks high-permeability channels, diverts flow to medium-permeability regions, and enhances macroscopic sweep efficiency. Microscopically, it mobilizes residual oil via normal stress action and a filamentous transport mechanism, improving oil-washing efficiency and increasing ultimate oil recovery. This study demonstrates the technical feasibility and practical effectiveness of the optimized weak gel system for enhancing oil recovery in heterogeneous reservoirs, providing critical technical support for the efficient development of medium–high-permeability reservoirs with high water cut. Full article

Carbon dioxide (CO₂) has been widely applied in gas flooding for reservoir development due to its remarkable oil recovery potential. However, because its viscosity is lower than that of water and most crude oils, severe channeling often occurs during the flooding process, resulting in a significant reduction in the sweep efficiency. To address this issue, foam flooding has attracted considerable attention as an effective method for controlling CO₂ mobility. In this study, a compound foam system was developed with alpha-olefin sulfonate (AOS) as the primary foaming agent, alcohol ethoxylate (AEO) and cetyltrimethylammonium bromide (CTAB) as co-surfactants, and partially hydrolyzed polyacrylamide (HPAM) as the stabilizer. The optimal system was screened through evaluations of comprehensive foam index, salt tolerance, oil resistance, and shear resistance. Results indicate that the AOS+AEO formulation exhibits superior foaming ability, salt tolerance, and foam stability compared with the AOS+CTAB system, with the best performance achieved at a mass ratio of 2:1 (AOS:AEO), balancing both adaptability and economic feasibility. A heterogeneous reservoir model was constructed using parallel core flooding to investigate the displacement performance and blocking capability of the system. Nuclear magnetic resonance (NMR) imaging was employed to monitor in situ oil phase migration and clarify the recovery mechanisms. Experimental results show that the compound foam system demonstrates excellent conformance control performance, achieving a blocking efficiency of 84.5% and improving the overall oil recovery by 4.6%. NMR imaging further reveals that the system effectively mobilizes low-permeability zones, with T₂ spectrum analysis indicating a 4.5% incremental recovery in low-permeability layers. Moreover, in reservoirs with larger permeability ratio, the system exhibits enhanced blocking efficiency (up to 86.5%), though the incremental recovery is not strictly proportional to the blocking effect. Compared with previous AOS-based CO₂ foam studies that primarily relied on pressure drop and effluent analyses, this work introduces NMR imaging and T₂ spectrum diagnostics to directly visualize pore-scale fluid redistribution and quantify sweep efficiency within heterogeneous cores. The NMR data provide mechanistic evidence that the enhanced recovery originates from selective foam propagation and the mobilization of residual oil in low-permeability channels, rather than merely from increased flow resistance. This integration of advanced pore-scale imaging with macroscopic displacement analysis represents a mechanistic advancement over conventional CO₂ foam evaluations, offering new insights into the conformance control behavior of AOS-based foam systems in heterogeneous reservoirs. Full article

Gel foam exhibits excellent applicability in fractured-vuggy reservoirs, effectively plugging flow channels and enhancing oil recovery. However, due to the harsh high-temperature environment and the complex and variable fracture-vuggy structure in reservoirs, gel foam may undergo structural changes during its migration, which can affect its flow properties and plugging efficiency. Therefore, investigating the migration characteristics of gel foam in fractured reservoirs through visual experiments is of significant practical importance. In this study, migration experiments with different foam systems were conducted using the visualized vuggy model. The migration stability of foam was characterized by combining the sweep range and liquid drainage rate, and the impact of temperature on the migration characteristics of gel foam was explored. Additionally, a profile control experiment was performed using the fractured-vuggy network model, analyzing and summarizing its mechanisms for enhancing oil recovery in fractured-vuggy reservoirs. The results showed that, in the vuggy model, compared with ordinary foam and polymer foam, gel foam showed a lower drainage rate, higher foam retention rate and wider sweep range, and could form stable plugging in fractured-vuggy reservoirs. An increased temperature accelerated the thermal expansion of gas and changes in liquid film characteristics, which led to the expansion of foam migration speed and sweep range. Although a high temperature increased the liquid drainage rate of foam, it was still lower than 3%, and the corresponding foam retention rate was higher than 97%. In addition, the gel foam had a strong profile control ability, which effectively regulated the gas migration path and improved the utilization degree of remaining oil. Compared with the first gas flooding, the recovery of subsequent gas flooding was increased by 18.85%, and the final recovery of the model reached 81.51%. Comprehensive analysis revealed that the mechanism of enhanced oil recovery by gel foam mainly included density control, foam regeneration, flow redirection, stable plugging, and deep displacement by stable gel foam. These mechanisms worked synergistically to contribute to increased recovery. The research results fully demonstrate the application advantages of gel foam in fractured-vuggy reservoirs. Full article

Computational fluid dynamics (CFD) models have been widely used to evaluate the hydrodynamic and gas exchange performances of oxygenators, which are crucial in supporting patients with lung diseases or failure. However, while CFD models have been effective in analyzing oxygen transfer, they have not adequately addressed the experimentally demonstrated effects of varying sweep gas flow rates on CO₂ removal. This is a critical gap, as sweep gas flow directly influences the CO₂ transfer efficiency in oxygenators. To fill this gap, we extend our previously developed 1D mathematical model into a 3D computational framework to predict both blood pressure drops and the rates of oxygen and CO₂ transfers in oxygenators. The comparison between our model predictions and experimental data validates the model’s capability in capturing the overall trends in CO₂ transfer/removal rates under different sweep gas flow rates. The results also demonstrated that our model can predict CO₂ removal more accurately, particularly in scenarios where adjusting the sweep gas flow rate is essential for optimizing the oxygenator performance. Full article

In an integrated gasification combined cycle (IGCC), a gasification process produces a gas stream from a solid fuel, such as coal or biomass. This gas (syngas or synthesis gas) resulting from the gasification process contains carbon monoxide, molecular hydrogen, and carbon dioxide (other gaseous components may also be present depending on the gasified solid fuel and the gasifying agent). Separating hydrogen from this syngas stream has advantages. One of the methods to separate hydrogen from syngas is selective permeation through a palladium-based metal membrane. This separation process is complicated as it depends nonlinearly on various variables. Thus, it is desirable to develop a simplified reduced-order model (ROM) that can rapidly estimate the separation performance under various operational conditions, as a preliminary stage of computer-aided engineering (CAE) in chemical processes and sustainable industrial operations. To fill this gap, we present here a proposed reduced-order model (ROM) procedure for a one-dimensional steady plug-flow reactor (PFR) and use it to investigate the performance of a membrane reactor (MR), for hydrogen separation from syngas that may be produced in an integrated gasification combined cycle (IGCC). In the proposed model, syngas (a feed stream) enters the membrane reactor from one side into a retentate zone, while nitrogen (a sweep stream) enters the membrane reactor from the opposite side into a neighbor permeate zone. The two zones are separated by permeable palladium membrane surfaces that are selectively permeable to hydrogen. After analyzing the hydrogen permeation profile in a base case (300 °C uniform temperature, 40 atm absolute retentate pressure, and 20 atm absolute permeate pressure), the temperature of the module, the retentate-side pressure, and the permeate-side pressure are varied individually and their influence on the permeation performance is investigated. In all the simulation cases, fixed targets of 95% hydrogen recovery and 40% mole-fraction of hydrogen at the permeate exit are demanded. The module length is allowed to change in order to satisfy these targets. Other dependent permeation-performance variables that are investigated include the logarithmic mean pressure-square-root difference, the hydrogen apparent permeance, and the efficiency factor of the hydrogen permeation. The contributions of our study are linked to the fields of membrane applications, hydrogen production, gasification, analytical modeling, and numerical analysis. In addition to the proposed reduced-order model for hydrogen separation, we present various linear and nonlinear regression models derived from the obtained results. This work gives general insights into hydrogen permeation via palladium membranes in a hydrogen membrane reactor (MR). For example, the temperature is the most effective factor to improve the permeation performance. Increasing the absolute retentate pressure from the base value of 40 atm to 120 atm results in a proportional gain in the permeated hydrogen mass flux, with about 0.05 kg/m².h gained per 1 atm increase in the retentate pressure, while decreasing the absolute permeate pressure from the base value of 20 bar to 0.2 bar causes the hydrogen mass flux to increase exponentially from 1.15 kg/m².h. to 5.11 kg/m².h. This study is linked with the United Nations Sustainable Development Goal (SDG) numbers 7, 9, 11, and 13. Full article

This research makes a strong focus on improving fluid dynamics inside the reservoir after stimulation for enhancing oil and gas well performance, particularly in terms of increasing the Gas–oil ratio (GOR) and injectivity leading to a better productivity index (PI). Advanced stimulation operation using new formulated emulsified acid treatment greatly improves the reservoir permeability, allowing for better fluid movement and less formation damage. This, in turn, results in injectivity increases of at least 2.5 times and, in some situations, up to five times the original rate, which is critical for sustaining reservoir pressure and ensuring effective hydrocarbon recovery. The emulsified acid outperforms typical 15% HCl treatments in terms of dissolving and corrosion rates, as it is tuned for the reservoir’s pressure, temperature, permeability, and porosity. This dual-phase technology increases injectivity by five times while limiting the environmental and material consequences associated with spent and waste acid quantities. Field trials reveal significant improvements in injection pressure and a marked reduction in circulation pressure during stimulation, underscoring the treatment’s efficient penetration within the rock pores to enhance oil flow and sweep. This increase in performance is linked to the creation of the wormholing impact of the emulsified acid, resulting in improved fluid dynamics and optimized reservoir efficiency, as shown by the enhanced gas–oil ratio (GOR) in the four mentioned cases. A critical component of attaining such improvements is the capacity to effectively analyze and forecast reservoir behavior prior to executing the stimulation in real life. Engineers can accurately forecast injectivity gains and improve fluid injection tactics by constructing an advanced predictive model with low error margins, decreasing the need for time-consuming and costly trial-and-error approaches. Importantly, the research utilizes sophisticated neural network modeling to forecast stimulation results with minimal inaccuracies. This predictive ability not only diminishes the dependence on expensive and prolonged trial-and-error methods but also enables the proactive enhancement of treatment designs, thereby increasing efficiency and cost-effectiveness. This modeling approach based on several operational and reservoir factors, combines real-time field data, historical well performance records, and fluid flow simulations to verify that the expected results closely match the actual field outcomes. A well-calibrated prediction model not only reduces uncertainty but also improves decision making, allowing operators to create stimulation treatments based on unique reservoir features while minimizing unnecessary costs. Furthermore, enhancing fluid dynamics through precise modeling helps to improve GOR management by keeping gas output within appropriate limits while optimizing liquid hydrocarbon recovery. Finally, by employing data-driven modeling tools, oil and gas operators can considerably improve reservoir performance, streamline operational efficiency, and achieve long-term production growth through optimal resource usage. This paper highlights a new approach to optimizing reservoir productivity, aligning with global efforts to minimize environmental impacts in oil recovery processes. The use of real-time monitoring has boosted the study by enabling for exact measurement of post-injectivity performance and oil flow rates, hence proving the efficacy of these advanced stimulation approaches. The study offers unique insights into unconventional reservoir growth by combining numerical modeling, real-world data, and novel treatment methodologies. The aim is to investigate novel simulation methodology, advanced computational tools, and data-driven strategies for improving the predictability, reservoir performance, fluid behavior, and sustainability of heavy oil recovery operations. Full article

This study focuses on optimizing the Reverse Water Gas Shift (RWGS) reaction system using a membrane reactor to improve CO₂ conversion efficiency. A one-dimensional simulation model was developed using FlexPDE Professional Version 8.01/W64 software to analyze the performance of ZSM-5 membranes integrated with 0.5 wt% Ru-Cu/ZnO/Al₂O₃ catalysts. The results show that the membrane reactor significantly outperforms the conventional Packed Bed Reactor by achieving higher CO₂ conversion (0.61 vs. 0.99 with optimized parameters), especially at lower temperatures, due to its ability to remove H₂O and shift the reaction equilibrium selectively. Key operational parameters, including temperature, pressure, and sweep gas flow rate, were optimized to maximize membrane reactor performance. The ZSM-5 membrane showed strong H₂O selectivity, with an optimum operating temperature of around 400–600 °C. The problem is that many reactants permeate at higher temperatures. Subsequently, a Half-MPBR design was introduced. This design was able to overcome the reactant permeation problem and increase the conversion. The conversion ratios for PBR, MPBR, and Half-MPBR are 0.71, 0.75, and 0.86, respectively. This work highlights the potential of membrane reactors to overcome the thermodynamic limitations of RWGS reactions and provides valuable insights to advance Carbon Capture and Utilization technologies. Full article

Transforming H₂O and CO₂ into solar fuels like syngas is crucial for future sustainable transportation fuel production. Therefore, the MgFe₂O₄/CO₂ splitting cycle was thermodynamically scrutinized to estimate its solar-to-fuel energy conversion efficiency in this investigation. The thermodynamic data required to solve the modeling equations were obtained using the HSC Chemistry program. The reduction non-stoichiometry was assumed to be equal to 0.1 for all computations. One of the study’s primary goals was to examine the impact of the inert sweep gas’s molar flow rate on the process parameters related to the MgFe₂O₄/CDS cycle. Overall, it was understood that the effect of the inert sweep gas’s molar flow rate on the thermal reduction temperature was significant when it increased from 10 to 40 mol/s compared to the rise from 40 to 100 mol/s. The energy needed to reduce MgFe₂O₄ increased slightly due to the surge in the inert sweep gas’s molar flow rate. In contrast, the energy penalty for heating MgFe₂O_4-δred from the re-oxidation to thermal reduction temperature significantly decreased. Including gas-to-gas heat exchangers with a gas-to-gas heat recovery effectiveness equal to 0.5 helped reduce the energy demand for heating the inert sweep gas. Overall, although the rise in the inert sweep gas’s molar flow rate from 10 to 100 mol/s caused a drop in the thermal reduction temperature by 180 K, the total solar energy needed to drive the cycle was increased by 85.7 kW. Accordingly, the maximum solar-to-fuel energy conversion efficiency (13.1%) was recorded at an inert sweep gas molar flow rate of 10 mol/s, which decreased by 3.7% when it was increased to 100 mol/s. Full article

This paper examines the feasibility of converting a Heavy-Duty (HD) Spark Ignition (SI) Compressed Natural Gas (CNG) engine to biogas fuel. A One-Dimensional (1D) simulation tool was used to model a commercially available HD SI CNG engine. The model was validated by comparing experimental and computed in-cylinder pressure, brake power, fuel, and air mass flow rates. The engine was then modified to use biogas with an injection system based on existing designs from the literature. A Spark Advance (SA) sweep was performed to assess the engine’s performance at full load. The chosen equivalence ratio was 0.85, and the engine speed was 1500 rpm. The Maximum Brake Power (MBP) and Maximum Brake Efficiency (MBE) operating points were identified. Partial load analysis was conducted starting from the MBP conditions. Results in terms of brake power, brake efficiency, and NO_x emissions are presented. Conversion to biofuel results in a reduction in power and efficiency of 33% and 4%, respectively, at 1500 rpm and full load conditions. Brake Specific NO_x emissions remained comparable. This numerical study demonstrates the feasibility of biogas conversion for HD SI engines, offering a renewable fuel alternative to reduce greenhouse gas emissions, though with trade-offs in power and efficiency. Full article