The Tazhong No. 1 condensate gas reservoir in Tarim Basin shows complex storage spaces and strong heterogeneity. To intuitively assess the production performance characteristics of the condensate gas reservoir and understand the occurrence mechanism of condensate oil, an experimental device and method for visualized simulation of depletion exploitation in fracture-vuggy condensate gas reservoirs were established. The condensate oil precipitation characteristics and dynamic parameters of different reservoir types during depletion were tested. The research indicates that the condensate oil occurrence characteristics in the single-fracture-vuggy model are similar to those in the multi-fracture-vuggy model. Condensate oil that precipitates on the pore walls slides down as droplets under the influence of gravity, eventually gathering at the corners of the lower areas of the pores. Unlike porous reservoirs, fracture-vuggy condensate gas reservoirs exhibit significant retrograde vaporization during the late stages of depletion production. As the depletion rate increases, the recovery degree of condensate oil also rises. For the single-fracture-vuggy model, recovery increases by 7.68%, and for the multi-fracture-vuggy model, by 9.85%, when the depletion rate is 6 MPa/h compared to 3 MPa/h. The results of this research provide crucial insights for developing technical measures to enhance condensate oil recovery in the middle and late stages of fracture-vuggy condensate gas reservoir development.

The global carbon emissions resulting from the combustion of fossil fuels have had a negative impact on the environment. This research presents an in-depth analysis of the economic and environmental impacts associated with carbon storage initiatives in Malaysia. It also explores the distributional effects of carbon pricing and the perception of its regressive nature as a significant challenge. Urgent and thorough measures are necessary to reduce carbon emissions from oil and gas, thereby mitigating the catastrophic consequences of climate change and facilitating a transition towards a more sustainable and environmentally responsible energy system. A comprehensive assessment of the potential impacts of Malaysia's carbon pricing policy on the Organization's economy and environment. Four cases were analyzed: (1) New Field Development, (2) New Field Development with Carbon Tax, (3) New Field Development with CCS and Carbon Tax, and (4) New Field Development with CCS, Carbon Tax, and Subsidy. The results show Internal Rates of Return (IRR) of approximately 16.5%, 14.5%, 12.8%, and 15.0-15.5% respectively. These findings highlight that a combined policy mix (carbon tax + CCS + subsidies) substantially improves economic viability, aligning with global best practices and offering a strong policy pathway for Malaysia.

With the growing challenges in conventional hydrocarbon exploration, shale oil has emerged as a critical target for future energy supply. The Qingshankou Formation (K₂qn) in the southern Songliao Basin holds significant shale oil potential. However, the complex laminae architecture and poorly constrained lithofacies have hindered a clear understanding of shale oil enrichment mechanisms, thereby limiting efficient exploration and development. This study focuses on the K₂qn shale in the Changling Sag, where a comprehensive characterization of lithofacies and pore structures is carried out using an integrated approach of core description, geochemical analysis, and multi-scale imaging techniques, including thin-section petrography, micro-XRF, MAPS, QEMSCAN, and fluid injection experiments. Three types of argillaceous laminae are identified to reveal significant textural and structural heterogeneity in the shale. Pore systems are dominated by interparticle pores and microfractures, with microfractures playing a crucial role in enhancing pore connectivity and fluid transport. The results also indicate that reservoir quality is jointly controlled by organic matter content, mineral composition, and laminae characteristics. Importantly, two enrichment models are proposed that the layered mixed shale with medium to high organic matter represents a migration-accumulated model influenced by external hydrocarbon input, and the laminated siliceous shale and the mixed shale, both with moderate to high organic content, follow in-situ accumulation patterns dominated by thermal transformation of indigenous organic matter. These findings offer critical geological insights to guide more accurate reservoir prediction and targeted exploration in the lacustrine shale systems.

Tight sandstone gas reservoirs exhibit low gas abundance and extensive gas-bearing lithology, presenting promising prospects for future exploration and development. However, their exploitation in the Sichuan Basin is severely constrained by low recovery efficiency, high water saturation, and pronounced retrograde condensation phenomena. In this study, we aim to analyze the complex fluid flow behavior within these reservoirs to overcome these challenges. To achieve this, a comprehensive experimental program is utilized, encompassing nuclear magnetic resonance, micro-computed tomography, core flooding, and retrograde condensation tests. The analysis reveals that tight sandstone reservoirs feature low porosity, low permeability, and poor pore connectivity, with pore structures predominantly composed of nanometer-to 10-μm-size micropores. Pore size distributions in both Type I and Type II reservoirs exhibit multimodal characteristics, rendering them highly sensitive to stress changes and condensate-induced formation damage. Permeability demonstrates significant hysteresis effects during cyclic changes in confining pressure. Precisely, after two complete cycles of increasing and decreasing confining pressure, average permeability damage rates reach 52.08% and 46.1%, respectively. This indicates damage levels ranging from moderate-weak to moderate-strong. In contrast, variations in pore pressure exhibit minimal impact on permeability. Under irreducible water saturation conditions, the average gas phase damage rate is 64%. Furthermore, initiating fluid flow within the reservoir requires a specific threshold pressure. The average damage rate caused by retrograde condensation is 24.7%. This experimental investigation elucidates the reservoir's pore-throat characteristics, the dynamics governing gas-water and gas-oil flow, and the damage patterns associated with retrograde condensation. These insights provide critical foundational data for optimizing development strategies and designing effective stimulation measures to achieve enhanced recovery.

We investigate full-field petroleum production forecasting using machine learning. A data-driven proxy model that predicts field-scale production under various operational scenarios is proposed. It offers an alternative to time-consuming numerical simulators for assisting operational oilfield management decisions like designing waterflooding schedules and quantifying production loss caused by schedule delays. Its accuracy is validated with real-world datasets. Beyond its practical application, we leverage the proposed workflow to conduct a systematic comparison of several machine learning and deep learning algorithms using four datasets and three forecast horizons. Such critical and systematic analysis is long overdue and seems to be extremely rare in related works, which consistently favor increasingly intricate neural networks, despite the presence of relatively limited and sparse datasets, low-dimensional input variables and the existence of well-defined physical laws to guide input selection. Our comparative study suggests deep learning is an overkill in the context of full-field production forecasts, without any tangible benefits in terms of accuracy. Kernel-based models consistently outperform neural-based architectures in this multi-dimensional analysis. In addition, we find evidence that algorithmic generalization in the full-field context seems to be more influenced by the spatial density of production data than by dataset size. The data-driven proxy model and the investigative findings of this work can help engineers apply machine learning to petroleum production forecasting. On a broader scale, our results endorse the Green AI paradigm, which advocates for the use of compact architectures that deliver good accuracy with a low computational cost.

The FM fault-fractured-vuggy volatile oil reservoir exhibits significant heterogeneity and rapid production decline. Furthermore, there are notable differences in the effects of depletion development, and the impact of volatile oil degassing on water injection parameters remains unclear. This paper established artificial cores that replicate both single-fractured-vuggy and multi-fractured-vuggy full-diameter systems, reflecting a typical reserves ratio of pores, fractures, and caves in the FM oilfield. Concurrently, water injection experiments were conducted for both single-well and multi-well units after natural energy depletion had occurred. The results indicated favorable development when single-well units opened the lower part of the fracture-vuggy zone, allowing for depletion below bubble pressure at an early stage. Due to dissolved gas flooding at the top of reservoirs, crude oil depletion recovery reached over 67%. The filling of fractures and caves led to delayed degassing: single-phase seepage before degassing was influenced by reservoir physical properties. In contrast, multiphase seepage after degassing was affected by fluid viscosity. The single-well units employed large-volume water injection huff-n-puff techniques, resulting in a pronounced gravity oil displacement effect. This method improved cumulative crude oil recovery by more than 5%. Additionally, it was recommended that multi-well units adopt a deep injection and shallow production development strategy, with continuous water flooding enhancing oil recovery by over 40%. However, during the asynchronous injection-production stage, the recovery improvement was limited to only 1%.

The formation of inorganic scales such as calcium sulfate and barium sulfate during water injection in oilfields can severely impair productivity by clogging pores and reducing rock permeability. This study evaluates the performance of two industrial scale inhibitors—diethylenetriaminepenta (methylene phosphonic acid) (DTPMP) and polyphosphinocarboxylic acid (PPCA)—and their hybrid blends in mitigating scale formation under laboratory and simulated reservoir conditions. Laboratory assessments included scale prediction modeling, static bottle tests, dynamic tube blocking, turbidity, and core-flooding experiments to determine inhibition efficiency, retention behavior, and formation damage potential. Thermodynamic modeling using OLI Studio predicted the maximum scaling tendency at a mixture of 70% injection water and 30% formation water, which was used as the baseline brine for testing. The 50:50 PPCA:DTPMP blend achieved the highest inhibition efficiency (>90%) for both calcium and barium sulfate scales at only 50 ppm, outperforming individual inhibitors. Under dynamic tube blocking conditions, the hybrid system maintained stable pressure profiles, effectively delaying scale nucleation and reducing pressure buildup. Turbidity analyses showed lower light transmittance values (5.6%-6.1%) for the blend, confirming its superior resistance to particle formation and growth. Core-flooding experiments further revealed that the hybrid inhibitor minimized permeability loss to only 5%, compared with 72% in the blank and 9-13% for the single-inhibitor cases. Adsorption/desorption experiments confirmed rapid adsorption (equilibrium in <2 pore volumes) and sustained desorption over 20 pore volumes, indicating strong and prolonged retention. These results demonstrate a positive synergistic effect between the nucleation inhibition mechanism of PPCA and the crystal growth suppression mechanism of DTPMP. The 50:50 hybrid formulation offers a practical, efficient, and economically viable solution for long-term scale management under reservoir conditions.

This paper presents a highly selective water control system designed to address declining oil production in offshore wells caused by rising water cuts while overcoming the poor selectivity of current chemical water control materials. The system was developed by copolymerizing octadecyl methacrylate and butyl methacrylate, followed by emulsion polymerization to prepare oil-soluble polymers. This resulted in a water-dispersible, high-selectivity water control system in the form of an emulsion dispersion. The feasibility of its field application was assessed via median particle size and reservoir stability tests, and the system's water control performance, visual performance, and underlying mechanism were evaluated. The test results showed that the median droplet diameter of the emulsion in the system was 0.431 μm, and it remained stable for at least 8 h under reservoir conditions. The system demonstrated excellent selective water-control capabilities, with a water-phase permeability blocking rate of 82.42% and an oil-phase permeability blocking rate of 5.02%. The mechanism of action was further explored via visualized flat plate tests and low-field nuclear magnetic resonance scanning displacement experiments on rock cores. The findings suggest that oil-soluble particles exhibit effective selective water-control performance and can be applied in water control operations in offshore oil fields.

Surfactant-Alternating-Gas (SAG) utilizes foam to reduce gas mobility and improve reservoir sweep efficiency in gas-injection enhanced oil recovery and carbon capture and storage. Although SAG is known to have many benefits that increase hydrocarbon recovery, liquid injectivity is typically very poor during a SAG process. Conventional foam simulators use the Peaceman model to estimate injection-well pressure. However, because they assume uniform saturation in the grid block, they do not account for near-wellbore saturation distribution that improves gas and liquid injectivities during a SAG process. We use a conventional foam simulator to test the impact of grid refinement on injectivity. We compare simulation results to those with fractional-flow theory (FFT) using the a model very widely used in simulations. In addition, we test the effect of complete foam collapse at irreducible water saturation (S_wr), of neglecting the Peaceman model, and of disallowing foam in the injector grid block. We compare the transient behaviors and the average injectivities, calculated during one pore volume of injected fluid. Our results show that in a conventional simulation (including the Peaceman model) grid refinement increases gas and liquid injectivities. However, the results do not match FFT predictions. The assumption of complete foam collapse at S_wr increases gas injectivity (still without matching FFT results); however, it has a smaller impact on liquid injectivity and grid refinement results in an increase in gas and liquid injectivities. Excluding the Peaceman model reduces the error in simulated injectivities at coarse grid refinements but still without matching the FFT prediction. Finally, the procedure of excluding foam in the injection-well grid block gives average injectivities like our FFT calculations without requiring extraordinary grid refinement.

Effective proppant placement is essential for increasing the production of unconventional oil/gas reservoirs. It can substantially affect the fracture roughness. This paper presents a laboratory fracture model to quantify the effect of fracture roughness under well-controlled conditions. This model simulates fracture roughness by embedding particles into the walls. Via this model, the roughness can be well controlled and defined. The effect of fracture roughness location is quantified as an example to demonstrate the usefulness of the controllable fracture model. Using a fracture model with two-sided roughness, the relationships between roughness location, pump rate, and inlet location were established. The experimental results show that the rough surface in the middle resulted in a large void space in the fracture, which became more evident at a higher pump rate. This phenomenon has unexpected consequences for oil and gas production. Based on these experimental results, different sand injection modes were tested to reduce the void space caused by the surface roughness in the fractured middle. An injection mode that involves alternatively pumping proppants of different sizes was proposed to solve this problem effectively.