Search Results (9)

The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article

To address the challenges of water coning and early water breakthrough commonly encountered during the development of bottom-water gas reservoirs, this study establishes a fully coupled numerical simulation model integrating a horizontal wellbore, inflow control device (ICD) screens, and a zonal water control system. A novel “dual inflow performance index” method is introduced for the first time, enabling separate calculation of the pressure drops induced by gas and water phases flowing through the ICDs, thereby improving the accuracy of pressure simulations throughout the production lifecycle. The model divides the entire production system into four physically distinct subsystems, the bottom-water gas reservoir, ICD screens, production compartments, and the horizontal wellbore, which are dynamically coupled through transient interflow exchange. Based on geological parameters from the SPE10 dataset, the model simulates realistic production scenarios. The results show that the proposed model accurately captures the time-dependent increase in ICD pressure drop as fluid properties evolve during production. Moreover, the zonal water control method outperforms the single ICD-based control strategy in water control performance, achieving a 23% reduction in cumulative water production. Additionally, the water control intensity of the ICD screens increases nonlinearly with the reduction in the number of openings. In highly heterogeneous reservoirs with significant permeability contrast, effective suppression of water coning can only be achieved by setting a minimal number of openings in the high-permeability compartments, resulting in up to a 15% reduction in cumulative water production. The timing of production compartment shutdown exerts a significant influence on water control performance. The optimal strategy is to first identify the water breakthrough point through unconstrained production simulation as production with all eight ICD screen openings fully open and then shut down the high-permeability production compartment around this critical time. This approach can suppress cumulative water production by up to 27%. Overall, the proposed model offers a practical and robust tool for optimizing completion design and water control strategies in complex bottom-water gas reservoirs. Full article

With the unconventional energy sector (e.g., shale gas) increasingly focused on precision drilling and cost-effective extraction, slim-hole horizontal well technology is gaining prominence. However, drill string dynamics in narrow, complex fluid environments are not fully understood. This study presents a novel bidirectional fluid–structure interaction (FSI) model, uniquely integrating recursive algorithms with the Moving Particle Semi-implicit (MPS) method to couple drill string–wellbore contact with drilling fluid interactions. Key findings show that drilling fluid significantly impacts drill string behavior; for instance, it can reduce natural frequencies by 20–25%, while stiff formations amplify lateral resonance risks. Optimizing fluid properties can substantially cut energy losses, though TREE is marginally elevated when viscosity exceeds the threshold (2.5 × 10⁻⁵ m²/s). The drill string typically displaces rightward, but higher viscosity can shift it left; a moderate friction coefficient aids centering. Excessive lateral displacement impairs cuttings removal, affecting fracturing. These insights enable actionable strategies: adjusting fluid viscosity and drag reducers can optimize drill string position and enhance cleaning. This research provides a framework for energy-efficient drilling in complex reservoirs, balancing efficiency with wellbore integrity and improving outcomes in the unconventional energy sector. Full article

In the production process of horizontal wells, wellbore temperature data play a critical role in predicting shale gas production. This study proposes a coupled thermo-hydro-mechanical (THM) mathematical model that accounts for the influence of the stress field when determining the distribution of wellbore temperature. The model integrates the effects of heat transfer in the temperature field, gas transport in the seepage field, and the mechanical deformation of shale induced by the stress field. The coupled model is solved using the finite difference method. The model was validated against field data from shale gas production, and sensitivity analyses were conducted on seven key parameters related to the stress field. The findings indicate that the stress field exerts an influence on both the wellbore temperature distribution and the total gas production. Neglecting the stress field effects may lead to an overestimation of shale gas production by up to 12.9%. Further analysis reveals that reservoir porosity and Langmuir volume are positively correlated with wellbore temperature, while permeability, Young’s modulus, Langmuir pressure, the coefficient of thermal expansion, and adsorption strain are negatively correlated with wellbore temperature. Full article

As the energy sector transitions toward decarbonisation, low-to-intermediate temperature geothermal resources in sedimentary basins—particularly repurposed oil and gas fields—have emerged as promising candidates for sustainable heat and power generation. Despite their widespread availability, the development of these systems is hindered by gaps in methodology, oversimplified modelling assumptions, and a lack of integrated analyses accounting for long-term reservoir and wellbore dynamics. This study presents a detailed, simulation-based framework to evaluate geothermal energy extraction from depleted petroleum reservoirs, with a focus on low-enthalpy resources (<150 °C). By examining coupling reservoir behaviour, wellbore heat loss, reinjection cooling, and surface energy conversion, the framework provides dynamic insights into system sustainability and net energy output. Through a series of parametric analyses—including production rate, doublet spacing, reservoir temperature, and field configuration—key performance indicators such as gross power, pumping requirements, and thermal breakthrough are quantified. The findings reveal that: (1) net energy output is maximised at optimal flow rate (~70 kg/s for a 90 °C reservoir), beyond which increased pumping offsets thermal gains; (2) doublet spacing has a non-linear impact on reinjection cooling, with larger distances reducing thermal interference and pumping energy; (3) reservoirs with higher temperatures (<120°C) offer significantly better thermodynamic and hydraulic performance, enabling pump-free or low-duty operations at higher flow rates; and (4) wellbore thermal losses and reinjection effects are critical in determining long-term viability, especially in low-permeability or shallow fields. This work demonstrates the importance of a coupled, site-specific modelling in assessing the geothermal viability of petroleum fields and provides a foundation for future techno-economic and sustainability assessments. The results inform optimal design strategies and highlight scenarios where the geothermal development of oil and gas fields can be both technically and energetically viable. Full article

An integrated dynamic analysis and prediction method for shale gas reservoirs based on wellbore coupling has been developed, focusing on optimizing well production. This method integrates a three-dimensional geological model, a mechanical model, simulations of fracture propagation, and a numerical simulation in a gas reservoir to establish a continuous-flow model that links the gas reservoir, fractures, and wellbore after hydraulic fracturing. It enables comprehensive integrated production dynamic analysis and predictions. The process begins by trajectory modeling and attribute assignment. Subsequently, based on the regional tectonic map, contour lines are drawn, regional tectonic surfaces are established, segmentation and clustering are performed, and appropriate fracturing fluids and proppants are selected to simulate fracture network expansion. Finally, the integrated dynamic simulation model of the gas reservoir and wellbore is constructed using the Petrel RE module, considering the combined effects of wellbore flow and reservoir seepage. The model was developed from a single well and through three-dimensional geological modeling, the simulation of fracture propagation in hydraulic fracturing, and a numerical simulation. An integrated dynamic licensing and prediction methodology was established for a shale gas integration model with wellbore-gas reservoir coupling. Additionally, this study analyzes and establishes the optimal pressurization timing and regime for the pressurizer to enhance gas well production. The model was successfully applied for historical matching and dynamic predictions in a block in the southern Sichuan region, producing results closely aligned with the actual data, thus providing a robust tool for predicting the future production profiles of shale gas wells. Full article

This paper develops a model of the multi-wing finite-conductivity fractures considering stress sensitivity for low-permeability bi-zone composite gas reservoirs. A new semi-analytical solution in the Laplace domain is presented. The main solution includes the theory of source function, Laplace integral transformation, perturbation technique, and Stehfest numerical inversion. Wellbore pressure is obtained by coupling solutions of reservoirs and fractures. The results showed that the pressure and derivative curves generated by this model include a bi-linear flow stage. The model was validated by comparing its results with Wang’s results and the commercial well-test simulator; the results showed excellent agreement. This model illustrated the seepage characteristic of acid fracturing stimulated wells during refracturing treatment and how they are influenced by reservoir and hydraulic fractures parameters (asymmetrical factor and fractures distribution, etc.). The model is suitable to solve the solution of arbitrary-angle hydraulic fracture in refracturing and helpful to understand the transient production rate characteristic of the multi-wing fracturing well. Full article

Based on the whole life cycle process of the economic exploitation of natural gas hydrate, this paper proposes the basic problem of stabilizing the wellbore for the basic conditions that must be met to ensure the integrity of the wellbore for exploitation: revealing the complex mechanism of fluid–solid–heat coupling in the process of the physical exchange of equilibrium among gas, water, and multiphase sand flows in the wellbore, hydrate reservoir, and wellbore, defining the interface conditions to ensure wellbore stability during the entire life cycle of hydrate production and proposing a scientific evaluation system of interface parameters for wellbore integrity. Full article

Depleted gas reservoirs are appealing targets for carbon dioxide (CO ${}_2$ ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO ${}_2$ and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO ${}_2$ injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO ${}_2$ within the wellbore. When the reservoir pressure is below the CO ${}_2$ bubble-point pressure, and CO ${}_2$ is injected in its liquid or supercritical state, CO ${}_2$ will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO ${}_2$ transitions from the dense-state to the gas-state, CO ${}_2$ density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO ${}_2$ expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO ${}_2$ expansion is associated with the Joule–Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO ${}_2$ injectivity. Understanding the transient multiphase phase flow behavior of CO ${}_2$ within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO ${}_2$ from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO ${}_2$ within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO ${}_2$ heating at the wellhead are assessed. Full article