Mechanical properties of nodular natural gas hydrate-bearing sediment

Natural gas hydrate is a relatively realistic alternative energy source to conventional fossil fuels with considerable reserves. Natural gas hydrate sediments are widely distributed in marine sediment on continental margins. In this study, a numerical modeling method for sediment containing nodular gas hydrates is developed using the two-dimensional discrete element simulation software. The effects of saturation, confining pressure, and nodule radius on the mechanical properties of heterogeneous nodular gas-hydrate-bearing sediment were analyzed using the stress-strain, fracture development, and partial body strain curves, as well as force chain distribution. The results indicated that the mechanical strength of sediment containing round nodular gas hydrates was proportional to the gas hydrate saturation and simulated confining pressure. When hydrate saturation was low, the failure strength of the gas-hydrate-bearing sediment diminished as the nodule radius increased. The simulations showed that variations in sediment porosity influenced the development and evolution of the shear band, resulting in higher porosity around the shear band. These results were analyzed from the perspectives of saturation and confining pressure to determine the failure and deformation law of simple nodular gas hydrate-bearing sediment and provide theoretical support for the subsequent study of the exploitation method of shallow buried deep gas hydrates.Document Type: Original articleCited as: Jiang, Y., Zhang, R., Ye, R., Zhou, K., Gong, B., Golsanami, N. Mechanical properties of nodular natural gas hydrate-bearing sediment. Advances in Geo-Energy Research, 2024, 11(1): 41-53. https://doi.org/10.46690/ager.2024.01.0

Evaluating the Effect of New Gas Solubility and Bubble Point Pressure Models on PVT Parameters and Optimizing Injected Gas Rate in Gas-Lift Dual Gradient Drilling

Gas-lift dual gradient drilling (DGD) is a solution for the complex problems caused by narrow drilling windows in deepwater drilling. Investigations are lacking on using oil-based drilling fluid in DGD, which is the principal novel idea of the present study. This research compares the results obtained from two new models with those of Standing’s correlations for solubility and bubble point pressure. Nitrogen was selected as the injection gas, then the PVT behavior of drilling fluid (oil/water/Nitrogen) in gas-lift DGD was evaluated and compared by coding in MATLAB. Then, these results were used to calculate the bottom hole pressure and finally investigate the optimization of injected gas flow rate. According to the achieved results, the Standing model has some errors in evaluating the PVT behavior of “Nitrogen and oil-based drilling fluids” and is not recommended for the mixtures in the gas-lift DGD. Regarding optimizing gas flow rate, a discrepancy was observed between pressure values obtained from the new models and the Standing model for the case of high liquid flow rates at low gas flow rates because of the difference in PVT parameters. The developed codes are deposited on an online data repository for future users. This study lays the foundation for better planning of drilling in deepwater drilling projects

Evaluating the Effect of New Gas Solubility and Bubble Point Pressure Models on PVT Parameters and Optimizing Injected Gas Rate in Gas-Lift Dual Gradient Drilling

Gas-lift dual gradient drilling (DGD) is a solution for the complex problems caused by narrow drilling windows in deepwater drilling. Investigations are lacking on using oil-based drilling fluid in DGD, which is the principal novel idea of the present study. This research compares the results obtained from two new models with those of Standing’s correlations for solubility and bubble point pressure. Nitrogen was selected as the injection gas, then the PVT behavior of drilling fluid (oil/water/Nitrogen) in gas-lift DGD was evaluated and compared by coding in MATLAB. Then, these results were used to calculate the bottom hole pressure and finally investigate the optimization of injected gas flow rate. According to the achieved results, the Standing model has some errors in evaluating the PVT behavior of “Nitrogen and oil-based drilling fluids” and is not recommended for the mixtures in the gas-lift DGD. Regarding optimizing gas flow rate, a discrepancy was observed between pressure values obtained from the new models and the Standing model for the case of high liquid flow rates at low gas flow rates because of the difference in PVT parameters. The developed codes are deposited on an online data repository for future users. This study lays the foundation for better planning of drilling in deepwater drilling projects

An Analytical Hierarchy-Based Method for Quantifying Hydraulic Fracturing Stimulation to Improve Geothermal Well Productivity

Hydraulic fracturing (HF) has been used for years to enhance oil and gas production from conventional and unconventional reservoirs. HF in enhanced geothermal systems (EGS) has become increasingly common in recent years. In EGS, hydraulic fracturing creates a geothermal collector in impermeable or low-permeable hot dry rocks. Artificial fracture networks in the collector allow for a continuous flow of fluid in a loop connecting at least two wells (injector and producer). However, it is challenging to assess the fracability of geothermal reservoirs for EGS. Consequently, it is necessary to design a method that considers multiple parameters when evaluating the potential of geothermal development. This study proposes an improved fracability index model (FI) based on the influences of fracability-related geomechanical and petrophysical properties. These include brittle minerals composition, fracture toughness, minimum horizontal in-situ stress, a brittleness index model, and temperature effect to quantify the rock’s fracability. The hierarchical analytic framework was designed based on the correlation between the influencing factors and rock fracability. The results of the qualitative and quantitative approaches were integrated into a mathematical evaluation model. The improved fracability index model’s reliability was evaluated using well logs and 3D seismic data on low-permeable carbonate geothermal reservoirs and shale gas horizontal wells. The results reveal that the improved FI model effectively demonstrates brittle regions in the low-permeable carbonate geothermal reservoir and long horizontal section of shale reservoir. We divide the rock fracability into three levels: FI > 0.59 (the rock fracability is good); 0.59 > FI > 0.32 (the rock fracability is medium); and FI < 0.32, (the rock fracability is poor). The improved FI model can assist in resolving the uncertainties associated with fracability interpretation in determining the optimum location of perforation clusters for hydraulic fracture initiation and propagation in enhanced geothermal systems

An Analytical Hierarchy-Based Method for Quantifying Hydraulic Fracturing Stimulation to Improve Geothermal Well Productivity

Hydraulic fracturing (HF) has been used for years to enhance oil and gas production from conventional and unconventional reservoirs. HF in enhanced geothermal systems (EGS) has become increasingly common in recent years. In EGS, hydraulic fracturing creates a geothermal collector in impermeable or low-permeable hot dry rocks. Artificial fracture networks in the collector allow for a continuous flow of fluid in a loop connecting at least two wells (injector and producer). However, it is challenging to assess the fracability of geothermal reservoirs for EGS. Consequently, it is necessary to design a method that considers multiple parameters when evaluating the potential of geothermal development. This study proposes an improved fracability index model (FI) based on the influences of fracability-related geomechanical and petrophysical properties. These include brittle minerals composition, fracture toughness, minimum horizontal in-situ stress, a brittleness index model, and temperature effect to quantify the rock’s fracability. The hierarchical analytic framework was designed based on the correlation between the influencing factors and rock fracability. The results of the qualitative and quantitative approaches were integrated into a mathematical evaluation model. The improved fracability index model’s reliability was evaluated using well logs and 3D seismic data on low-permeable carbonate geothermal reservoirs and shale gas horizontal wells. The results reveal that the improved FI model effectively demonstrates brittle regions in the low-permeable carbonate geothermal reservoir and long horizontal section of shale reservoir. We divide the rock fracability into three levels: FI > 0.59 (the rock fracability is good); 0.59 > FI > 0.32 (the rock fracability is medium); and FI < 0.32, (the rock fracability is poor). The improved FI model can assist in resolving the uncertainties associated with fracability interpretation in determining the optimum location of perforation clusters for hydraulic fracture initiation and propagation in enhanced geothermal systems

Review of the Leak-off Tests with a Focus on Automation and Digitalization

The drilling and research communities are leading the way toward more digitally-controlled operations to ensure that the drilling process takes place as safely and gently as possible with the lowest possible carbon footprint. Today’s cutting-edge operations are run on large high-performance drilling installations where operations are largely run remotely from the driller’s operating station. Digitalization of the drilling process is the goal for performing drilling operations remotely from onshore. Leak-off test (LOT) or extended leak-off test (XLOT) plays a critical role in the petroleum industry. Therefore, recognizing all affecting parameters on LOT/XLOT and Formation integrity test (FIT) performance is vital. Because, in some cases, it is not possible to fully understand what happened during the test, having a deep insight into the LOT procedure is very important. One of the current study's main objectives is to thoroughly explain all stages of these tests and assemble all the significant parameters. Thus, many scientific papers on these tests were deeply reviewed and were classified into four main groups focusing on the application of LOT/XLOT (i) in stress estimation and geomechanical studies, (ii) concerning hydraulic fracturing, (iii) concerning wellbore stability, and (iv) numerical modeling, and then, the corresponding discussions were conducted. It was found that in-situ stress estimation is the most common application of the leak-off test. Moreover, considering the importance of LOT and the desire to digitize operations in the oil and gas industry, it was found that the automatic LOT/XLOT is a fully required approach. The primary purpose of this study, which is hence considered its main contribution, is to prepare a LOT flowchart that would set off the further code development tasks of the field. The fundamental code of the present study was written and checked using a real dataset in a Python environment. The results were satisfying and indicated a successful start, which lays a foundation for future automated LOT/XLOT tests

Influence of gas hydrate saturation and pore habits on gas relative permeability in gas hydrate-bearing sediments: theory, experiment and case study

Gas relative permeability characterization is of key significance to model the behavior of gas flow in gas hydrate-bearing sediments. The present study proposes a novel model to relate gas relative permeability to gas hydrate saturation based on X-ray micro-CT imaging information of xenon hydrate pore-scale distribution in sand sediments. Lattice Boltzmann method (LBM) was used to obtain permeability values of xenon hydrate-bearing sediments via micro-CT data. The results showed that gas relative permeability (Kr) versus gas hydrate saturation (Sh) data are consistent with the new model and the imitative effect is relatively better than that of the simple Corey model. Besides, we calculated gas relative permeability versus gas hydrate saturation curves for various pore habits via idealized models. Experimental measurements and simulation results showed that the grain-coating gas hydrate exhibits the highest gas relative permeability, while pore-filling gas hydrate exhibits the lowest values of gas relative permeability, and the cementing gas hydrate ranges in between. We validated the new gas relative permeability calculation model by applying it to the well logging data of gas hydrate reservoirs. Our results showed that the novel model is beneficial for permeability characterization of gas hydrate reservoirs and gas relative permeability calculations

A novel hybrid method for gas hydrate filling modes identification via digital rock

Gas hydrates are one of the most abundant clean energy resources and can effectively solve the energy crisis with a lower carbon footprint. Gas hydrates typically exhibit complex microscopic filling modes, including adhesive mode, cemented mode and scattered mode. Furthermore, the scientific understanding of such filling modes and the associated petrophysical parameters is essential for successful exploitation and development of hydrate formations. However, a precise identification of such filling modes remains a big challenge. Thus, here we proposed a novel hybrid gas hydrate filling mode identification method via digital rock technique. The hybrid method uses a combination of multiple methodologies. Firstly, the dry core samples were scanned by the high-resolution micro-scale 3D X-ray computed tomography (μCT) and the digital rock models were built. Then the resistivity was simulated as a function of gas hydrate saturation with three idealized gas hydrate-filling modes. The differences between the resistivity of three idealized gas hydrate-filling modes were analyzed, and based on the correlations obtained, the idealized gas hydrate saturation calculation models were formulated. We then considered well log data from a real hydrate reservoir in order to evaluate the application of proposed hydrate saturation model and identify the filling mode. Essentially, the gas hydrate saturation results from digital rock models and field well logging data are compared, and the filling modes in the research reservoir were successfully identified

Insights into the multiscale conductivity mechanism of marine shales from Wufeng–Longmaxi Formation in the southern Sichuan Basin of China

Gas-bearing capacity is an important feature in the evaluation of the different properties of shale. The calculation of adsorbed gas and free gas content is the focus of the shale gas-bearing capacity evaluation, for which gas saturation is a key parameter. In the present study, the target area was the marine shales of the Wufeng–Longmaxi Formation in the Dingshan, Jiaoshiba, and Changning areas of the southern Sichuan Basin in China, while the purpose of the study was the more effective characterization of Langmuir’s volume and Langmuir’s pressure using well-logging data. The application of new well-logging technologies in the evaluation of shale gas-bearing capacity is seldom studied, and the conventional sand-mudstone saturation models calculate the shale gas-bearing capacity with low accuracy. Therefore, this study systematically analyzed the shale conductivity mechanism, which laid the foundation for a new calculation model for shale gas saturation. The analysis results of the influencing factors of shale conductivity in the study area showed that the resistivity of shale in the interlayer is mainly affected by the thin low-resistivity layers, and the resistivity of shale in laminates is affected by clay minerals, pyrite, overmature conductive organic matter, and pore fluids. Moreover, this study further clarified the main controlling factors of the conductivity mechanism by implementing a multiscale analysis. Herein, on the meter-scale, the influence of thin low-resistivity layers on the shale resistivity was characterized based on a horizontal resistivity model; on the centimeter-scale, the influence of pore fluids on shale resistivity was investigated based on the rock electrical experiments; and on the nanometer-scale, the influence of clay minerals, pyrite, and organic materials on shale resistivity was examined based on digital rock technology and numerical simulation of the electrical properties. The results showed that the factors affecting the conductivity of the shale, from the strongest to the weakest, are conductive organic matter, thin low-resistivity layer, clay mineral, pore water, and pyrite, respectively

The Failure Mechanism of Methane Hydrate-Bearing Specimen Based on Energy Analysis Using Discrete Element Method

Studying the failure mechanism of methane hydrate specimens (MHSs) is of great significance to the exploitation of methane hydrate. Most previous studies have focused on the macro or micromechanical response of MHS under different conditions. However, there are a few studies that have investigated the mechanical response mechanism of MHS based on energy evolution. Therefore, in this study, a numerical model of the methane hydrate-bearing sediments was constructed in the particle flow code (PFC) environment. Then, the numerical model was validated using the conducted laboratory tests; and a series of numerical tests were conducted under different methane hydrate saturation conditions, and the obtained results were analyzed. These results qualitatively describe the main mechanical properties of the methane hydrate-bearing sediments from the viewpoint of energy evolution. The simulation results indicated that during the shear test, the bond breaks at first. Then, the soil particles (sediments) start to roll and rarely slid before shear strength arrives at the highest value. Around the highest shear strength value, more soil particles begin to roll until they occlude with each other. Strain softening is induced by the combined action of the breakage of the hydrate bond and the slipping of soil particles. The higher the hydrate saturation is, the more obvious the strain softening is. Considering that a good agreement was observed between the numerical simulation results and the laboratory test results, it can be concluded that the numerical simulation approach can complement the existing experimental techniques, and also can further clarify the deformation and failure mechanism of various methane hydrate-bearing sediments. The results obtained from the present study will contribute to a better understanding of the mechanical behavior of the gas hydrate-bearing sediments during hydrate dissociation and gas exploitation