The Bass Gas Scale Breaker initiative represents a strategic and technically innovative response to formation water scaling challenges within the Yolla field in the Bass Basin. Implemented as part of Beach Energy’s broader production optimisation program, the project aimed to improve well performance and maximise production through targeted chemical intervention. Located in the Bass Strait, BassGas produces from the Yolla field, through the Yolla A platform which is located 147 km off the coast of southern Victoria. Gas is processed through the BassGas plant which supplies gas to the Victorian transmission system through the Lang Lang – Pakenham pipeline. After a period of decline, this initiative involved a novel integrated review process involving collaboration of Beach teams to analyse how production could be optimised across all of the BassGas asset. The team chose to deal with the declining production from the major producer Yolla 6, which appeared to be impaired. Working with service partners and subject matter experts in the industry, Beach Energy Production Optimisation teams proposed a new initiative to remove downhole scale from the well, including a downhole chemical treatment deployed via existing topside process equipment and using an OSPAR Gold rated chelating system. This operation was a first for the Bass Basin. The result was a successful treatment of the wells in the field, which saw a favourable production increase from less than 300 kSm3/d before the initial treatment program to a peak of 1000 kSm3/d following the re-treatment of all producing wells. The enhanced production rates were sustained with routine re-application of the treatment every 2–6 months on key wells. The cross-collaborative team coupled these well treatments with other production optimisation initiatives like advanced process control and compression optimisation for a holistic approach to asset optimisation.

Aromatic carboxylic acids (ACAs) play a critical role in determining the disposal strategy of oilfield produced water (PW). In this work, we report a single-molecule nanopore sensor for the discrimination of six distinct ACAs. By employing an organic macrocycle as an adapter with the wild-type α-hemolysin nanopore, each ACA generates a characteristic current blockade, enabling clear discrimination based on the number of aromatic rings and carboxyl groups. The sensing signals remain unaffected by a 10-fold excess of phenols, metal ions, and polycyclic aromatic hydrocarbons. Furthermore, nuclear magnetic resonance, theoretical calculations, and nanopore experiments for carboxylic acid derivatives with varying hydrophilic and hydrophobic groups reveal that highly selective ACA recognition synergistically relies on size matching, hydrophilic interactions, and electrostatic effects. Notably, this strategy allows direct, label-free, and rapid quantification of 9-anthracenecarboxylic acid (9-AA) in authentic PW samples, demonstrating specific target detection within a complex matrix and highlighting the potential of nanopore technology for on-site environmental analysis.

A Review on Treatment Technologies for High-NaHCO3 Produced Water: Principles, Applications, and Future Perspectives

During water injection development in low-permeability reservoirs, BaSO4 scaling is prone to occur due to incompatibility between high-salinity formation water and injected water, severely affecting oilfield development efficiency. This paper systematically developed and evaluated the performance of a composite BaSO4 scale remover. Chelating agents, conversion agents, dispersants, and penetrants were optimized to construct an efficient composite scale removal system. Combined with core flooding experiments, operational parameters and processes were optimized. The results show that an efficient scale removal system was developed: 15% DTPA-5K + 8% C6H11O7Na + 6% DTPMP + 0.2% JFC (balance water), achieving a scale removal efficiency of 98.4% at pH = 11. Simulated core experiments indicated a permeability recovery rate of 87% at an injection rate of 0.02 mL min−1 and an injection volume of 1.5 PV. Field applications demonstrated that this system effectively removes BaSO4 scale blockages in injection and production wells. For injection well A21, the injection pressure decreased by 20.8%, water injection volume increased by 200%, and liquid production increased by 136% after treatment. For production well P17, liquid production increased by 136%, oil production increased by 148%, and flowing pressure increased by 31.8%. The research results provide theoretical basis and technical support for the prevention and treatment of BaSO4 scale in low-permeability reservoirs.

Impact of order–disorder in secondary minerals on the multicomponent geothermometry of formation waters and geothermal waters

This study investigates the microscopic oil recoverycharacteristicsof natural depletion and liquid huff-n-puff in ultralow-permeabilityconglomerate reservoirs of the Mahu Oilfield. A series of experimentswere conducted on conglomerate cores to simulate natural depletion,followed by three rounds of liquid huff-n-puff, utilizing nuclearmagnetic resonance (NMR) to quantitatively characterize oil recoveryand mobile pore-throat radius threshold. The results demonstrate thatnatural depletion yields limited recovery, with average recoveriesof 9.9%, 8.9%, and 4.8% for cores of high, medium, and low permeability,respectively. In contrast, liquid huff-n-puff significantly enhancesrecovery, with surfactant A solution achieving the highest incrementalrecovery (24%) due to its superior interfacial tension reduction capability(0.03 mN/m). Surfactant B solution and simulated formation water increasedthe recovery by 17% and 14%, respectively. During natural depletion,the oil distinctly mobile pore-throat radii ranged from 0.27 to 1.7μm for dual-peak pore structures (Types I–II) and from0.04 to 0.09 μm for single-peak cores (Type III). Posthuff-n-puff,these thresholds decreased, indicating enhanced oil drainage fromsmaller pores. Notably, surfactant injection does not impede waterimbibition in nanosubmicron pores, highlighting synergistic effectsbetween interfacial tension reduction and capillary imbibition. Surfactanthuff-n-puff is most effective for dual-peak cores with micrometer-scalepores, whereas imbibition dominates recovery in nanopore-dominatedsystems. Additionally, the first huff-n-puff round contributed thehighest recovery increment, with diminishing returns in subsequentrounds. This work provides the first quantitative analysis of surfactanthuff-n-puff efficacy postdepletion in conglomerate reservoirs, offeringpractical guidance for enhancing recovery in similar unconventionalsystems.

Scale formation in oil and gas operations reduces production efficiency and increases costs, especially in high-salinity and high-temperature environments. Conventional inhibitors often fail in such harsh conditions. This study examines diethylenetriaminepentaacetic acid (DTPA) and glutamic acid diacetic acid (GLDA) as primary scale inhibitors under dynamic flow conditions. The experiments use a dynamic scale loop (DSL) that mimics reservoir conditions, with a commercial phosphonate scale inhibitor acting as a comparison benchmark. Experiments were performed at temperatures of 200°F, 275°F, and 338°F, using high salinity water (TDS of 58,500ppm) representing seawater and formation water (TDS of 274,740ppm) at mixing ratios of 50:50 and 80:20, with injection rates of 1 and 10 cc/min, and inhibitor concentrations ranging from 0.1 to 1.0wt%. Scale formation was strongly accelerated by increasing temperature, flow rate, and ion interaction in the 50:50 brine mixture. All inhibitors delayed scale formation relative to the uninhibited case; however, performance varied significantly with operating conditions. Inhibitor effectiveness was evaluated using a normalized improvement factor relative to prescale conditions. DTPA demonstrated strong performance at elevated temperatures, while GLDA showed more consistent performance at higher flow rates. The phosphonate inhibitor performed well under moderate conditions but showed reduced effectiveness under more severe HTHS conditions. Notably, GLDA at 338°F, with a 50:50 brine mixture and a flow rate of 10 cc/min, delayed scale formation by 11-fold, the most significant improvement observed. These findings demonstrate that inhibitor performance is governed by both thermodynamic stability and kinetic effects and highlight the importance of condition-specific inhibitor selection. Overall, this study provides a systematic framework for evaluating scale inhibitors under realistic dynamic HTHS conditions and demonstrates the potential of chelating agents as effective alternatives for challenging environments.

Natural gas reservoirs characterized by high heterogeneity and containing bottom-bound water often face the problem of water intrusion, making it difficult to recover the recoverable gas. This paper addresses the issue of enhanced gas recovery in water-flooded reservoirs and, through high-temperature, high-pressure long-core displacement experiments, investigates the displacement effects of different reservoir properties and injection media (dry gas, N2, CO2) under simulated water-flooding conditions. The experiment utilized two sets of sandstone cores—one with moderate permeability (304.8 mD) and one with high permeability (1004.6 mD). Three cores from each set were spliced together to form a 0.9 m long core, simulating the gas injection and displacement process following water infiltration. The results indicate that while water intrusion occurs more rapidly in high-permeability reservoirs, gas injection yields better recovery results than in medium-permeability reservoirs. Among the three injection media, dry gas demonstrated the best displacement efficiency, followed by N2, with CO2 performing the worst. CO2 tends to react with highly mineralized formation water under high-temperature and high-pressure conditions, forming precipitates and causing energy to be absorbed by the water, which reduces displacement efficiency. It is recommended that dry gas injection be used for enhanced recovery in the moderate-permeability reservoirs of the Y gas field, while N2 injection may be considered for the high-permeability reservoirs to balance effectiveness and cost. The research results provide experimental support for subsequent gas injection to enhance gas recovery in this gas field.

One method to further enhance oil production is through tertiary recovery, also known as Enhanced oil recovery (EOR). The EOR method can increase production from wells by up to 75% recovery. One of the EOR technologies that has been applied for more than 50 years in the petroleum industry is polymer injection, which has proven effective in improving oil recovery. The objective of this study is to obtain an efficient polymer with good compatibility and viscosity. This research analyzes the compatibility and viscosity characteristics of Xanthan Gum (XG) polymer solutions and a mixture of Xanthan Gum with Cyclea barbata Miers (CHXG) in formation water with a salinity of 11,000 mg/L. Compatibility tests were conducted at concentrations of 1,000, 2,000, and 3,000 mg/L to determine the solubility of the polymer in formation water. The results show that both types of polymers have good compatibility, indicated by the absence of precipitation and the formation of clear and homogeneous solutions. Viscosity tests were carried out at room temperature and at elevated temperature (70°C) to evaluate the effect of temperature on the rheological properties of the solutions. The XG polymer exhibited a decrease in viscosity at 70°C, with the highest reduction of 24.3% at a concentration of 3,000 mg/L. In contrast, the CHXG polymer showed a significant increase in viscosity at high temperature, with the highest increase reaching 53.49% at the same concentration. These results indicate that the addition of Cyclea barbata Miers can enhance the thermal stability and viscosity performance of the polymer under reservoir conditions at 70°C, whereas the use of Xanthan Gum alone results in a decrease in viscosity at the same temperature.

As reservoir development enters the middle and late stages, variations in formation pressure and water cut lead to significant changes in liquid supply capacity. Under conventional fixed stroke-per-minute (SPM) operation, the production capacity of beam pumping wells often fails to match the dynamically varying inflow, resulting in severe dynamic fluid level fluctuations and subsequent pump-off, gas locking, and abnormal rod string loading. To address these issues, this paper develops a dynamic fluid level model based on the operating mechanism of beam pumping wells, explicitly incorporating system uncertainties and reservoir disturbances. On this basis, a tube-based robust model predictive control (Tube-RMPC) strategy is proposed, in which nominal predictions are combined with local feedback compensation to effectively mitigate model uncertainties and external disturbances. Simulation results demonstrate that, compared with conventional PID control and traditional MPC methods, the proposed approach achieves superior performance in dynamic fluid level tracking accuracy, disturbance rejection, and closed-loop stability.

Produced water (PW), generated during oil and gas extraction, is a complex wastewater characterized by high salinity, hydrocarbons, and heavy metals, making treatment and beneficial reuse challenging. Bioremediation offers a sustainable treatment alternative, but the extreme physicochemical conditions of PW inhibit the growth and activity of most conventional microorganisms. This study evaluates the bioremediation potential and heavy metal tolerance mechanisms of the halophile, Modicisalibacter sp. strain Wilcox, isolated from PW. We examined its growth and benzene, toluene, ethylbenzene, and xylenes (BTEX) degradation capability under elevated salinity in defined media and raw PW, while assessing the effects and fate of metals individually and in multimetal mixtures. Strain Wilcox demonstrated exceptional tolerance to individual metals, including 100 mM arsenate, 100 mM manganese, 12.5 mM cadmium, and 7 mM zinc. Increasing metal concentrations and multimetal mixtures reduced BTEX degradation rates, with toxicity varying by metal species and salinity. In addition to hydrocarbon degradation, the strain removed 75-99% of Mn2+, Zn2+, Se4+, Pb2+, Cr3+, and Cu2+ via biosorption and bioaccumulation. Functional genomic analysis supported these phenotypes, revealing >70 metal resistance genes, 58 osmoregulation genes, and ∼70 genes associated with cross-protection against salt and metal stress, highlighting strain Wilcox's potential for bioremediation of PW.

This report presents the genome sequence of Robertmurraya sp. GLU-23, a potential coal-degrading bacterium isolated from coal seam producing water in Hancheng, Shaanxi, China. The draft genome, with 5,059,906 bp and 37.87% GC content, contains genes for polycyclic aromatic hydrocarbon biodegradation, suggesting its potential for coal degradation.

This study investigates a synergistic approach to integrate carbon dioxide (CO) mineralization with hypersaline produced water (PW) from the Mishrif formation in Iraq's Al-Zubair oil field to generate "smart water" for enhanced oil recovery (EOR).The experimental methodology involved carbonating PW at 50 bar and 30 C, followed by alkalinity adjustment to pH 10.4 using NaOH to induce mineral precipitation.A total precipitate yield of 8.78 g per 100 mL with significant CO sequestration capacity of 7.5 g CO/L, was recovered.X-ray diffraction (XRD), scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS ) analyses identified the crystalline mineral composition as calcite (CaCO 3 , 19.95 wt%), fluorite (CaF, 16.63 wt%), and halite (NaCl, 9.07 wt%), with the remaining approximately 54% composed of amorphous phases and poorly crystalline materials.The transformation into "smart water" achieved a 24.7% reduction in interfacial tension (IFT), decreasing from 61.43 mN/m to 46.28 mN/m, primarily driven by pH-dependent interfacial charge effects.Also, zeta potential measurements showed a charge reversal from +12.4 mV to -19.08 mV, suggesting a favorable environment for altering reservoir wettability toward a more water-wet state.Inductively coupled plasma and optical emission spectrometry (ICP-OES) measurements initially indicated an increase in calcium concentration (from 9.663 to 12,847 mg/L) in a system undergoing precipitation determined to be caused by precipitate heterogeneity, dissolution during sample dilution and matrix effects inherent to hypersaline brines at extreme pH values.Absence of magnesium in XRD while there is a small amount in ICP-OES and EDS prove the recent studies on Mishrif formation in presence of dolomite.

In depleted or low-pressure subsurface reservoirs, the formation of CO₂ hydrate at low temperatures, induced by vaporization and isenthalpic expansion during dense CO₂ injection, can significantly impair well injectivity. The formation of CO₂ hydrates is governed by multiple factors, including CO₂ availability and its solubility, the properties of the surrounding fluids, and the characteristics of the rock. A key parameter influencing water activity and CO₂ solubility is the salinity of in-situ brine, which affects both the thermodynamics and kinetics of hydrate formation. The impact of salinity varies with the type and concentration of dissolved salts. This study investigates the impacts of two prevalent formation water salts, NaCl and CaCl₂ on CO₂ hydrate induction time, hydrate saturation, rock permeability reduction, and their implications for CO₂ injectivity. Coreflood experiments were performed under dynamic flow conditions, supplemented by computed tomography (CT) scanning to provide in-situ saturation profiles. The primary aim is to establish a correlation between the aforementioned parameters and mean ionic activity, thereby facilitating a generalized application of the results irrespective of the specific salt type. Empirical results indicate a marginally extended induction period at elevated initial salinity levels. Furthermore, an increase in mean ionic activity correlates with a decrease in hydrate saturation, which consequently leads to less significant reductions in permeability and injectivity. • The effects of NaCl and CaCl₂ on CO₂ hydrate kinetics are investigated. • A correlation between hydrate saturation and ionic activity/permittivity is proposed. • The permeability of the porous medium is estimated based on the mean ionic activity.

High-fidelity numerical simulations of CO2 geological storage are computationally expensive, impeding the rapid assessment of leakage risks associated with mobile free gas. To address this, this study proposes a comprehensive data-driven framework ranging from mechanism analysis to parameter optimization. Leveraging a data set of 4,631 time-series samples derived from representative global sequestration projects, we constructed a generalized predictive model incorporating nine key geological and operational parameters. Among the tested algorithms, XGBoost demonstrated superior performance in capturing the temporal evolution of residual (RTI) and solubility trapping indices (STI). Crucially, the physics-based SHAP analysis quantified the geological controls: RTI is primarily driven by residual gas saturation via capillary hysteresis, while STI is strictly governed by formation water salinity, consistent with the thermodynamic limits of Henry’s Law. Furthermore, coupling the surrogate model with the NSGA-II algorithm generated Pareto-optimal solutions that effectively balance short-term safety and long-term stability. The optimization results establish strict quantitative screening criteria: formations with high permeability (>400 mD), ultralow salinity (<5 kppm), and moderate residual gas saturation (<0.22) are identified as optimal for safely restricting the initial mobile gas index to below 30% within the first 50 years. Large-scale Monte Carlo simulations (100,000 evaluations) confirm the robustness of these criteria. This framework bridges data-driven insights with physical mechanisms, providing a cost-effective tool for prefeasibility analysis and optimized scenario generation in CCUS projects.

Produced-water (PW) management in the Permian Basin faces tightening injection constraints, induced seismicity concerns, and volatile saltwater disposal (SWD) costs. At the same time, chemistry-rich PW contains dissolved constituents (e.g., Li, B, and Sr) that may be valorized if SWD recovery performance and market conditions support favorable techno-economics. Here, we develop an integrated decision-support framework that couples (i) chemistry-informed surrogate models for unit process performance (recovery, effluent quality, and energy/chemical intensity) with (ii) a network-based allocation model that routes PW from sources through pretreatment, optional treatment and mineral-recovery modules (e.g., desalination and direct lithium extraction), and end-use nodes (beneficial reuse, hydraulic fracturing reuse, mineral recovery/valorization, or Class II disposal). This is a screening-level demonstration using publicly available chemistry percentiles and representative pilot-reported performance windows; it is not a site-specific facility design or a bankable TEA for a particular operator. The optimization is posed as a tri-objective problem—to maximize expected net present value, minimize SWD, and minimize an injection-risk indicator R—subject to mass balance, capacity, quality, and regulatory constraints. Uncertainty in commodity prices, recovery fractions, and operating costs is propagated via Monte Carlo scenario sampling, yielding PARETO-efficient portfolios that quantify trade-offs between profitability and risk mitigation. Using the PW chemistry percentiles reported by the Texas Produced Water Consortium for the Delaware and Midland Basins, we derive screening-level break-even lithium concentrations and illustrate how lithium-carbonate-equivalent price and recovery govern the extent to which mineral revenue can offset SWD expenditures. Comparative brine benchmarks (Smackover Formation and Salton Sea geothermal systems) contextualize the Permian’s generally lower-Li PW and highlight transferability of the workflow across brine types. The proposed framework provides a transparent, extensible basis for design matrix planning under evolving injection limits, enabling risk-aware PW management strategies that reduce disposal dependence while improving water resilience.

The efficiency and safety of CO2 geological sequestration together with CO2-enhanced coalbed methane recovery (CO2-ECBM) depend on the dynamic evolution of coal–water–gas interfacial wettability under the influence of reservoir pressure, temperature, and the formation water chemistry. The wettability has a direct impact on the migration ability of CO2 into coal seams and the stability of the adsorption-sequestration and desorption efficiency of coalbed methane. Research has often overlooked the effect of in situ formation water on wettability, which may hinder accurate prediction of multiphase flow mechanisms in realistic environments. This study simulates in situ interactions among the CO2 formation water and coal for 25 days. Thus, it shows the wettability evolution in four stages. These stages are initial hydrophobicity, rapidly wetting, slowly wetting, and dynamic equilibrium. The formation water is acidic and multi-ionic in nature. This affects wettability through many mechanisms. These include mineral dissolution and precipitation, catalytic oxidation, and pore surface feedback. The impact of these mechanisms is greater than in low-salinity system. Moreover, this can bring about faster equilibration (20 days). The cause of equilibrium is the precipitation of secondary minerals (Fe(OH)3, amorphous SiO2, CaSO4), which self-limit reactions and smooth surface irregularities. The findings were used to propose a pressure regime in phases. These include low-pressure injection 0–5 days, medium- to high-pressure injection 5–10 days, gradual pressure reduction 10–20 days, and injection switch-off after 20 days for safe storage of CO2 in the long term. Overall, this study reveals the evolutionary pathway of coal wettability under reservoir conditions. Furthermore, it links the stage transitions to multiple mineral reactions, organic modifications, and pore-structure feedback. The kinetics derived present a basis for stage-wise pressure control concepts in CO2 storage and the CO2-ECBM process, which is experimentally anchored.

Inorganic scaling is a critical flow assurance challenge that significantly affects production in the oil industry, causing blockages in pipes and other equipment, operational downtime, and substantial economic losses. One strategy adopted to reduce these problems is the injection of chemical inhibitors, which keep the crystals in solution in the aqueous medium to prevent their deposition. The application of these substances, conveyed in monoethylene glycol (MEG - C2H6O2), is a strategy widely adopted by this industry. However, the effectiveness of this approach depends on the concentration and degree of homogenization of the inhibitor in the aqueous phase along the cross-section of the pipeline. Inadequate or insufficient injection of these products can exacerbate the problem, worsening the operational and financial impacts of fouling. In this context, this research presents a 3D numerical simulation of the two-phase flow consisting of oil and an aqueous phase formed by the formation water and monoethylene glycol, which is injected into the pipeline through a chemical injection valve (VIQ). To obtain the temperature, pressure, and velocity boundary conditions of the case, at the inlet of the oil and formation water and the outlet of the pipeline, the two-phase flow of these substances was simulated in 1D and steady state, using the ESSS ALFAsim® commercial software. In the 3D simulation, a multiphase, multicomponent, incompressible, and non-isothermal coupled formulation was used, using the Volume of Fluid (VOF) model, the species transport model, without chemical reactions, and considering the effects of turbulence, applying the standard classical κ-ε turbulence model, with enhanced wall treatment. A mesh refinement study was carried out to obtain a “convergent mesh” noting that even with a relatively refined mesh, the annular pattern could be lost due to excessive numerical diffusion. Preliminary results indicated that, for a sufficiently refined mesh, the annular pattern of the two-phase flow of the oil and aqueous phase was maintained, and the dispersion of the MEG was influenced by the interaction between the immiscible phases and the effects of turbulence. Our approach is a tool for better understanding the transport of these inhibitors in pipelines and a strategy for promoting the efficient prevention of inorganic scaling, reducing operating costs, and increasing the reliability of processes in the oil sector.

To address the technical challenge of severe performancedegradationof foaming agents caused by high-salinity formation water and condensateduring drainage gas recovery in tight gas wells, this study developeda composite foam system (BLZP) with excellent saltand oil tolerance. Through chemical modification, zwitterionic groups(sulfonate and quaternary ammonium) were introduced into the poly­(vinylalcohol) (PVA) backbone to synthesize a zwitterionicpolymer ZPVA, which served as a stabilizer. ZPVA was then optimized via orthogonal experiments withthe zwitterionic primary foaming agent dodecyl dimethyl betaine (BS-12) and the nonionic cofoaming agent lauryl dimethylamine oxide (LAO). Sodium perfluorononyloxybenzenesulfonate(OBS) was subsequently incorporated as an enhancer.Systematic characterization and evaluation demonstrated that ZPVA effectively suppresses polymer aggregation in 10 wt% NaCl or CaCl2 solutions, maintaining smaller hydrodynamicsizes and higher solution viscosities. The optimized BLZP system exhibited significantly enhanced interfacial dilatationalviscoelasticity in simulated high-salinity formation water (TDS 78,050mg/L). Oil-tolerance tests (with condensate content up to 60%) furtherrevealed that BLZP, owing to its compact and highlyelastic composite interfacial adsorption layer, effectively inhibitsoil droplet spreading and bridging-induced foam rupture. The decreasein initial foam height (H0) and 5 minfoam height (H5) was substantially lowerthan that of two commercial foaming agents. Even at 60% oil content, BLZP maintained H5 > 150mm,liquid carrying ratio >40%, and foam water content >4%, demonstratingoutstanding potential for field applications. This study providesan innovative chemical solution for efficient foam-assisted drainagegas recovery under challenging reservoir conditions.

Western Sichuan is located in a complex foreland thrust system, where intense multi-stage tectonic deformation makes hydrocarbon preservation a critical control on accumulation and exploration success. Focusing on the Middle Permian strata, this study aims to systematically evaluate hydrocarbon preservation conditions and clarify their spatial variability. Based on integrated seismic interpretation, formation water geochemistry, pressure data and regional geological and exploration information, a multi-indicator evaluation framework was established, incorporating tectonic deformation intensity (fault distance and fault development), exposed strata, caprock integrity and formation water characteristics. The results reveal a clear zonation of preservation conditions across western Sichuan. Near the Longmenshan fault front, dense faulting, severe caprock destruction and low-salinity NaHCO 3 –Na 2 SO 4 -type formation water indicate an open system with poor preservation. In the basin–mountain transition zone, fault activity weakens and partial caprock preservation remains, accompanied by moderate-salinity mixed NaHCO 3 –CaCl 2 water, reflecting intermediate preservation. Towards the basin interior, structures become stable and closed, regional gypsum–mudstone caprocks are well developed, and high-salinity CaCl 2 -type brines dominate, indicating long-term sealed systems and favourable preservation. These conditions are confirmed by multiple high-yield gas discoveries, including the Pingluoba-1 well with a tested gas flow of 66.76 × 10 4 m 3 /d. The proposed multi-indicator evaluation method and preservation zonation provide a robust geological basis for optimising exploration strategies in complex foreland basins such as western Sichuan.