Gas Hydrates In Sediments Research Articles

Geochemical and Physical Methods for Estimating the Saturation of Natural Gas Hydrates in Sediments: A Review

The saturation of natural gas hydrates is a key parameter for characterizing hydrate reservoirs, estimating hydrate reserves, and developing hydrate as an energy resource. Several methods have been proposed to estimate hydrate saturation, although most of these studies rely on logging and seismic data. However, the methods for estimating hydrate saturation from recovered core sediments have not been thoroughly reviewed, which hinders a deeper understanding, proper application, and the use of these experimental data to integrate geophysical and numerical model results with the actual geological conditions. In this paper, the methods widely used for estimating natural gas hydrate saturation from core sediments, including those based on pore water chemistry (Cl− concentration, δD, and δ18O values), gas volumetric analysis, and temperature anomaly, have been summarized in terms of the principle, estimation strategy, and issues to be considered of each method. The applicability, advantages and disadvantages, and scope of application of each method are also compared and discussed. All methods for estimating gas hydrate saturation have certain limitations. A comprehensive application of results from multiple methods could lead to a better understanding of the amount of gas hydrate in sediments, although the chlorinity of pore water is the most commonly used method of estimation.

Disturbed State Concept-Based Model Incorporating Strain-Softening Behavior for Gas Hydrate Sediments

Disturbed State Concept-Based Model Incorporating Strain-Softening Behavior for Gas Hydrate Sediments

A hydrate reservoir renovation device and its application in nitrogen bubble fracturing

Abstract. Natural gas hydrate (GH) is a significant potential energy source due to its large reserves, wide distribution, high energy density, and low pollution. However, the gas production rate of past gas hydrate production tests is much lower than the requirement of commercial gas production. Reservoir stimulation technologies like hydraulic fractures provide one potential approach to enhance gas production from GH. The reservoir reformation behavior of the hydrate-bearing sediments (HBSs), particularly sediments with a high clay content, is a complex process during a hydraulic fracturing operation which has been poorly understood and thus hardly predictable. This paper presents an experimental facility that was developed to analyze the hydraulic fracture mechanism in synthesized HBSs. This facility can be used to form GH in sediments, conduct visual observation of hydraulic fracturing experiments, and measure the permeability of HBSs under high-pressure (up to 30 MPa) and low-temperature conditions (from 253.15 to 323.15 K). It is mainly composed of a pressure control and injection unit, a low temperature and cooling unit, a cavitation unit, a visual sapphire reactor, and a data acquisition and measurement unit. The hydraulic fracture module consists of a gas cylinder, fracturing pump, hopper, proppant warehouse, and valves. The sapphire reservoir chamber is applied to observe and measure the fracture of HBSs during hydraulic fracturing. The permeability test module is composed of a constant-flux pump and pressure sensors, which can evaluate the permeability performance before and after the hydraulic fracture in HBSs. The fundamental principles of this apparatus are discussed. Some tests were performed to verify hydraulic fracture tests, and permeability tests could be practically applied in the HBS exploitation.

Seafloor morphology and potential gas hydrate distribution in the offshore Niger Delta

Bottom simulating reflectors (BSRs) and seismic pipe features have been used as proxies for defining the distribution of gas hydrate sediments in the offshore Niger Delta. This is the most extensive mapping of gas hydrate sediments in the Delta as of today. The seismic data merge comes from multiple surveys acquired with different parameters and seismic resolutions over the course of decades of oil and gas exploration in the region. Indicated gas hydrate distribution generally follows the structural fabric of the Niger Delta with BSRs occurring along the apexes of the thrust-related ridges that have bathymetric relief on the seafloor. The presence of swarms of seismic pipe features landwards of BSR locations suggests hydrates occur beyond BSR locations. The potential gas hydrates sediment acreage in offshore Niger Delta is 17600 sq-km, representing 20% of the area with a thickness of the gas hydrate stability zone reaching 440 m in the more outboard regions of the Delta. Total gas hydrates sediment coverage likely exceeds this value as BSRs become indistinguishable from sediment strata in regions of flat dips. The presence of double BSRs further suggests the presence of thermogenic gas hydrates in the region and allows to extend the thickness of the potential hydrate zone to 550 m in the outboard regions of the Delta.

Effective thermal conductivity for hydrate-bearing sediments under stress and local thermal stimulation conditions: A novel analytical model

The extraction of hydrates is accompanied by changes in the hydrate occurrence pattern, hydrate saturation, effective stress, temperature, and pore structure in porous sediment, making it difficult to predict the effective thermal conductivity (ETC) of hydrate-bearing sediments. Until now, accurately modeling the ETC of gas hydrate sediments during the exploitation process has remained a significant challenge. In this study, by combining pore compression theory, and particle thermal expansion theory, an analytical ETC model is derived to study the physical relations between the ETC of hydrate-bearing sediments under excess water or excess gas condition and various influencing parameters (e.g., hydrate occurrence pattern, effective stress, hydrate saturation, pore structure, and temperature). The proposed model is validated against test data. Furthermore, the effects of pore structures (e.g., initial porosity and radius fluctuation amplitude), effective stress, hydrate saturation, and hydrate occurrence pattern on ETC are revealed. Compared with the existing ETC models of hydrate-bearing sediments, our derived model takes more mechanisms into account, which makes our derived model more reasonable. In short, this model is of great significance to predict ETC and study the heat transfer in gas hydrate reservoirs, enabling engineers and scientists to have a better understanding of the hydrate exploitation process.

Theoretical analysis of shape factor of gas hydrate sediments under stress dependence

The Kozeny-Carman (KC) equation is used extensively to characterize the effective permeability of gas hydrate sediments. However, most existing modeling approaches ignore the changes in the effective stress, hydrate saturation, and pore structures of porous media, which significantly affect the extraction and exploration of gas hydrates. In addition, theoretical models that can accurately describe shape factors during the imbibition process and predict the effective permeability of gas hydrate sediments are rarely reported. This paper proposes a theoretical stress-dependent shape factor model to study the physical relations between the shape factor and relevant parameters (e.g., effective stress, hydrate saturation, effective porosity, and pore fractal dimension). Then, the derived model is extended to study the shape factor during the imbibition process. The two main novel features of the proposed model are: (1) it takes the effective stress, hydrate saturation, and pore structures into account; and (2) it can be used to study the evolution of shape factors during the imbibition process in gas hydrate sediments. The predictions from the developed model provide a good agreement with experimental results, which validates the model. In addition, based on the derived model, the effects of relevant parameters on shape factors are studied theoretically. From a practical standpoint, the model can not only estimate the effective permeability of gas hydrate sediments under stress dependence but also provide insight into the evolution of shape factor, pore structures (e.g., capillary total number, pore fractal dimension, tortuosity fractal dimension, and effective porosity) and hydrate pore habits during the extraction of hydrates.

Pore-Scale Investigation of Decomposition-Methods-Dependent Fluid Flow Properties in Hydrate-Bearing Sediments

Summary Depressurization (PD) and thermal stimulation (TS) are the primary methods for producing gas from natural gas hydrate (NGH) sediments. Fluid flow properties of the hydrate sediment, such as permeability, are fundamental parameters for simulating both processes. Most of the existing formulated permeability models are based on the numerical or experimental investigation of hydrate morphology evolution without considering the decomposition methods. In this study, we investigate the hydrate-decomposition-methods (PD and TS processes)-dependent fluid flow properties of hydrate sediments, which is achieved by microcomputed tomography (micro-CT) scanning of hydrate morphology evolution during PD- and TS-induced decomposition, as well as pore-scale modeling of fluid flow in the extracted 3D fluid-rock-hydrate images. We find that the decomposition behavior during TS is much more complicated than that during PD. The retardation zone in the PD sample increases the heterogeneity of the pore structure, while the secondary hydrates generated during TS cause even more heterogeneity in the pore space. The better facilitation of the TS method on hydrate split is favorable for the continuity of the gas phase. The pore-scale fluid flow simulation shows that the modified Kozeny-Carman (K-C) model is the best to describe the evolution of the normalized permeability with hydrate saturation during PD. However, a single model is not sufficient to describe the normalized permeability during TS decomposition due to the stronger heterogeneous porous structure reformed by the local accumulation of secondary hydrates. The two-phase flow capability is best at the initial stage of PD decomposition, while the two-phase flow region becomes wider as TS decomposition progresses. These results provide significant references for the simulation of the natural hydrate extraction process using different decomposition methods.

Positioning of horizontal well-bore in the hydrate reservoir using a custom developed coupled THMC solver

Natural gas hydrate sediments are considered as an unconventional source of energy found in deep sea reservoirs and permafrost regions under specific equilibrium conditions. To efficiently extract the gas from these sediments, well-bores need to be installed in these reservoirs followed by adopting an appropriate hydrate dissociation technique. This study presents a custom-developed coupled THMC solver to realistically quantify the gas production and associated sediment deformation. The numerical scheme solves coupled equations describing hydrate phase change kinetics and non-isothermal multiphase flow in porous media. The proposed THMC solver incorporates the HISS-MH constitutive model, enabling it to capture the non-linear geomechanical behavior of gas hydrate sediments, including strain-softening and dilation characteristics. The solver is validated against existing experimental results and a benchmark problem. Finally, the effect of different horizontal well-bore positions on vertical settlement and cumulative gas production is studied. The results indicate that the well-bore in the middle of the reservoir yields the highest cumulative gas production while differential settlement is minimum, thus making it a preferable location for placing the horizontal well-bores. This study contributes towards the development of a custom THMC solver with advanced models in addition to identifying the ideal location of the horizontal well-bore for efficient gas extraction.

Heat transfer study in the exploitation of argillaceous‐silt natural gas hydrate reservoirs

AbstractThe paper investigates the heat transfer in the exploitation of offshore argillaceous‐silt natural gas hydrate reservoirs considering sand control. The temperature prediction model is established in this investigation. The coupled pressure‐temperature model of the flowing fluid inside the wellbore is also presented. The sand control for argillaceous‐silt natural gas hydrate reservoirs mainly brings two effects into the temperature and pressure profiles simulation, including the moderate sand control and the Joule–Thompson effect. The moderate sand control is reflected by the volume and particle size of produced sand into the wellbore in the mathematical derivation. The Joule–Thompson is considered in the model due to the small diameter of sand control screens. The experiment is designed to measure the pressure drop caused by various mesh diameters of sand control screens. Subsequently, the regression relationship between the pressure drop and the mesh diameter is concluded to calculate the temperature change at the sand control screen. The simulation of heat transfer helps to analyze secondary hydrate formation risk in the wellbore. The proposed model identifies the high‐risk location of the secondary hydrate formation. The sand control effect and well geometry effect are discussed quantitatively. The strict sand control in the argillaceous‐silt natural gas hydrate (NGH) sediment exploitation reduces the risk of secondary hydrate formation significantly; however, it also has a negative effect on natural gas production. To balance the sand control and the prevention of secondary hydrate formation risk, it is suggested to install the heating electrode in the high‐risk location to ensure flow safety with acceptable sand control precision. The heat provided by heat electrodes is calculated by the model presented in this paper. The model can be used to determine the proper arrangement of heat electrodes. The paper also describes the secondary hydrate formation by adjusting the well geometry. The formation depth of the NGH reservoir and the sea interval should be considered in the risk analysis of the secondary hydrate formation. Additionally, the effects of wall thickness and wall thermal properties are evaluated and discussed. It is recommended to optimize the riser thickness with a small thermal conductivity value to minimize the secondary hydrate formation risk, which is more efficient compared to adjusting the cement sheath.

Imitating the effects of drilling fluid invasion on the strength behaviors of hydrate-bearing sediments: An experimental study

The drilling fluid invasion into hydrate-bearing sediments will change the geomechanical properties of the reservoir and may lead to uncontrolled geological disasters in the worst case. Native sediments are replaced with artificial samples in this study to investigate the effect of drilling fluid invasion on the strength behaviors of hydrate-bearing sediments. The triaxial test is used primarily to assess the strength behaviors of hydrate-bearing sediments at varying temperatures, pressures, and hydrate saturation levels. The process of water-based drilling fluid penetrating into hydrate-bearing sediments is then experimentally imitated under various experimental conditions, with reservoir temperature of 4°C and pore pressure of 10 MPa. The possible repercussions of drilling fluid invasion and hydrate phase transition are identified by testing the mechanical properties of sediments under various invasion times and temperatures. The findings reveal that when hydrate saturation rises from 5% to 35%, the gas hydrate sediments shift from strain hardening to strain softening, with the critical hydrate saturation value of transition is between 15% and 25%. Peak strength increases with increasing hydrate saturation and pressure, and decreases with increasing temperature, whether drilling fluid invasion is present or not. The peak strength, Young’s modulus, shear modulus, and secant modulus of hydrate sediments all decreased significantly after drilling fluid invasion, although the Poisson’s ratio rose. These mechanical parameters are related to temperature and pressure under the action of drilling fluid. Finally, engineering and research recommendations for reducing the risk of drilling fluid invasion and hydrate dissociation are made based on experimental findings and theoretical analysis. This study innovatively examine the geomechanical mechanical properties of drilling fluid invading hydrate reservoir, which is critical for avoiding production concerns.

Investigation on plugging prediction of multiphase flow in natural gas hydrate sediment with different field scales

The change in water–gas flowrate ratio is one of the main reasons to induce plugging occurrence in the natural gas hydrate (NGH) exploitation process, which significantly influences gas production efficiency. However, there was still no judgment factor to predict multiphase flow plugging in different field scales. Therefore, two sizes cylindrical reactors (Ф50, Ф15) were used in this study, and the difference in effective sectional velocity of water phase (vew) between the two reactors was about 12 times. The entire hydrate re-formation process was directly observed by magnatic resonance imaging (MRI), and the results proved that hydrate re-formation was the main factor for plugging in water–gas flow process. Moreover, the methane concentration gradient across the water and hydrate decreased with the decreasing water flowrate. Thus, the faster mass transfer process on water-hydrate interface enhanced the amount of hydrate re-formation in the two-phase flow process. After validation, the hydrate re-formation amount increased by 11.75% when the vew was reduced by 0.75 m/s. In other words, the higher water flowrate can effectively prevent the plugging of hydrate sediment under the same gas flowrate. Based on the above, the effective sectional velocity was first used to judge plugging occurrence for different scales hydrate sediment. At a given gas effective sectional velocity of 0.23 m/s, the flow plugging phenomenon did not appear when the effective sectional velocity of the water phase was higher than 3.59 m/s for two different scales of hydrate sediment. The results effectively evaluated the plugging occurrence in hydrate sediment with different scales during the water–gas flow process, and further established a bridge between the laboratory investigation and hydrate actual production test.

Experimental Insights Into the In Situ Formation and Dissociation of Gas Hydrate in Sediments of Shenhu, South China Sea

Natural gas hydrates as sustainable energy resources are inherently affected by mineral surfaces and confined spaces in reservoirs. However, the habits of hydrates in geological sediments are still an open question. In this work, we systemically studied the process of hydrate formation and dissociation in sediments from the Shenhu area of the South China Sea to examine the evolution of hydrate saturation and permeability in sediments and their relationship. Characterization of samples indicates that sediments of the Shenhu area are mainly composed of clay and fine sand grains and provide a large number of nanopores for hydrate accumulation. For in situ observations enabled by low-field nuclear magnetic resonance methods, the formation of hydrates shows a different kinetic behavior with an induction time compared to hydrate dissociation. Estimated by variations of hydrate saturation (%) over time, the rate of hydrate formation is around 12%/min, while the dissociation rate increases to 3%/min with the higher temperature. With the presence of hydrates, pore space and thus permeability of sediments decreased obviously by one and three orders of magnitude when the hydrate saturation is 20 and 45%, respectively. Compared to models with the assumption of grain-coating and pore-filling hydrates, the tendency of permeability evolution from NMR measurements is between fitted lines from models. It highlights that the existing models considering a single pattern of hydrate growth cannot precisely describe the relationship between permeability and hydrate saturation. Hybrid hydrate habits coexist in sediments resulting from heterogeneous pore structures and thus complex gas–water distributions.

Application of machine learning to quantification of mineral composition on gas hydrate-bearing sediments, Ulleung Basin, Korea

Mineral quantification is essential to evaluate gas hydrate (GH) resources because the mineral composition is closely related to the origin of sediment, the reservoir properties, and even the existence of GH. However, it is difficult to analyze the mineral compositions of GH-rich unconsolidated layers because of complex compositional combinations. Thus far, mineral composition has relied on experts’ analysis. In this study, a machine learning model was developed that can efficiently probe the mineral composition from the X-ray diffraction (XRD) patterns of GH sediments in the Ulleung Basin, Korea, which has a complex composition including 12 minerals. It is the first time that machine learning algorithms have been applied to complex natural GH sediment with 12 minerals, including amorphous materials. To build a reliable data-driven analysis model, after data acquisition and preprocessing were conducted, various machine learning algorithms were employed, including convolutional neural network (CNN), recurrent neural network (RNN), multi-layer perceptron (MLP), and random forest (RF). For data acquisition, 488 sediment samples were analyzed by XRD experiment, and the intensity profiles were manually analyzed by an expert to obtain their mineral compositions. In particular, the intensity profile according to the XRD angle of incidence serves as the input data, and the corresponding 12 mineral composition provides label data for supervised learning. The RF approach yields the best prediction result with an average mean absolute error (MAE) of 2.56%, and the other algorithms also exhibits reasonable performance with average MAEs of less than 3%. If XRD is newly performed for GH sediment, the intensity profile can be automatically analyzed by the trained machine learning model in seconds. This approach will enable experts to analyze mineral compositions efficiently and reliably. • Mineral composition was evaluated by machine learning (ML) from XRD profiles. • Gas hydrate (GH) sediment in Ulleung Basin, Korea comprises the twelve minerals. • The 488 data pairs (XRD profile, composition) were preprocessed by domain knowledge. • GH sediment including amorphous material was analyzed by ML for the first time. • The random forest approach performed better than deep learning algorithms.

Advances in Characterizing Gas Hydrate Formation in Sediments with NMR Transverse Relaxation Time

The formation process, structure, and distribution of gas hydrate in sediments have become focal points in exploring and exploiting natural gas hydrate. To better understand the dynamic behavior of gas hydrate formation in sediments, transverse relaxation time (T2) of nuclear magnetic resonance (NMR) is widely used to quantitatively characterize the formation process of gas hydrate and the change in pore characteristics of sediments. NMR T2 has been considered as a rapid and non-destructive method to distinguish the phase states of water, gas, and gas hydrate, estimate the saturations of water and gas hydrate, and analyze the kinetics of gas hydrate formation in sediments. NMR T2 is also widely employed to specify the pore structure in sediments in terms of pore size distribution, porosity, and permeability. For the recognition of the advantages and shortage of NMR T2 method, comparisons with other methods as X-ray CT, cryo-SEM, etc., are made regarding the application characteristics including resolution, phase recognition, and scanning time. As a future perspective, combining NMR T2 with other techniques can more effectively characterize the dynamic behavior of gas hydrate formation and pore structure in sediments.

Near-wellbore fracture initiation and propagation induced by drilling fluid invasion during solid fluidization mining of submarine nature gas hydrate sediments

Drilling in a natural gas hydrate formation is challenging due to the poor consolidation of the formation and the potential evaporation of the hydrate. The unreasonable down-hole pressure of the drilling fluid can not only lead to the wellbore instability, but also change the predrilling condition of the natural gas hydrate formation, thus leading to an instable wellbore. In this paper, the integrated discrete element method (DEM)-computational fluid dynamics (CFD) work flow is developed to study the wellbore instability due to the penetration of the drilling fluid into the hydrate formation during crack propagations. The results show that the difference between in-situ stresses and overpressure directly affect the drilling fluid invasion behavior. The lower hydrate saturation leads to an easier generation of drilling fluid flow channels and the lower formation breakdown pressure. The breakdown pressure increases with the increase of hydrate saturation, this also indicates that hydrates can enhance the mechanical properties of the formation. The induced cracks are initially accompanied with higher pressure of the drilling fluid. According to the rose diagram of the fracture orientation, a wider orientation of the fracture distribution is observed at higher pressure of the invasion fluid.

Statistical damage constitutive model based on self‐consistent Eshelby method for natural gas hydrate sediments

AbstractNatural gas hydrate (NGH) is widely distributed in marine sediments and continental permafrost, which is a promising energy resource. The sustainable and safe exploration and production of NGH requires fully understanding of its mechanical behaviors, which is still a challenge to our community. In this paper, a statistical damage constitutive model named SC‐SDCM is developed for NGH sediments. The NGH sediments are regarded as two phases: the matrix phase of solid mineral grains, pore fluid, and gas, and the inclusion phase of hydrate crystal. The effective elastic parameters of such two‐phase composite are estimated by self‐consistent method (SC) according to the equivalent inclusion principle of micromechanics. The mesoscopic element strength of the NGH sediments is described by the Weibull statistical distribution and the damage theory of composite materials. And then combined with the Drucker‐Prager failure criterion of microelement, the damage constitutive model of NGH sediments is established. The new SC‐SDCM is tested to be reliable and robust by triaxial experimental observations on artificial cores and naturally occurring samples under different confining pressures and hydrate saturations. The SC‐SDCM could properly describe the stiffness, peak strength, and strain softening properties of the NGH sediments. Moreover, the predictions of SC‐SDCM are closest to the experiment observations compared to several published constitutive models, especially for the near‐ and after‐damage stages with relatively high hydrate saturation.

Influence of Rock Wettability on THF Hydrate Saturation and Distribution in Sandstones

Natural gas trapped in hydrate deposits is a potentially enormous source of energy which can in principle be extracted from the underground reservoir structures. These reserves can potentially also catastrophically release very large quantities of greenhouse gases to the atmosphere. One key parameter which is well known to strongly influence fluid distribution, saturation, and production is rock wettability. However, the effect of wettability on gas hydrate in sediments has not been investigated yet. We thus used nuclear magnetic resonance (NMR) spectrometry to measure relaxation times (T2 and T1) and the corresponding surface relaxivity of tetrahydrofuran hydrate during the formation and dissociation in water- and oil-wet Bentheimer sandstones. We also measured the NMR porosities and hydrate saturations at different temperatures during hydrate formation/dissociation for both water-wet and oil-wet sandstones. Significantly higher hydrate saturation was observed in the water-wet sandstone (when compared to the oil-wet sandstone) at all stages of hydrate formation and dissociation. Furthermore, the T2 spectra moved from the lower relaxation domain (before hydrate formation) to the fast relaxation domain (after hydrate formation) in both water-wet and oil-wet sandstones. However, the water-wet sandstone generally had a T2 relaxation range due to the higher water affinity to the water-wet rock and the associated faster demagnetization of the water molecules. These results demonstrate that low-field NMR can be used to quantify the rock wettability and observe hydrate behavior in geologic sediments. This fundamental information thus aids in the development of gas extraction from hydrate reservoirs and the assessment of potential greenhouse gas emissions from such reservoirs into the atmosphere.

Physio-Chemical and Mineralogical Characteristics of Gas Hydrate-Bearing Sediments of the Kerala-Konkan, Krishna-Godavari, and Mahanadi Basins

The characteristics of the hydrate-bearing sediments affect the formation and dissociation of gas hydrate in sediments. The mineral composition, their dispersion, and chemical composition of hydrate-bearing sediment samples plays a dominant role in the hydrate stability condition and its economic development. In this paper, the physical properties of hydrate-bearing sediment of India are compared with each other. The sediment samples are taken from the Krishan-Godavari basin (Depth—127.5 and 203.2 mbsf), Mahanadi basin (Depth—217.4 mbsf), and Kerala-Konkan basin (Depth—217.4 mbsf). The saturation of the gas hydrate observed at these sites is between 3 and 50%. Particle size is an important parameter of the sediments because it provides information on the transportation and deposition of sediment and the deposition history. In the present study, we investigated the mineralogy of hydrate-bearing sediments by chemical analysis and X-ray Diffraction. XRD, FTIR, and Raman Spectroscopy distinguished the mineralogical behavior of sediments. Quartz is the main mineral (66.8% approx.) observed in the gas hydrate-bearing sediments. The specific surface area was higher for the sediment sample from the Mahanadi basin, representing the sediments’ dissipation degree. This characterization will give important information for the possible recovery of gas from Indian hydrate reservoirs by controlling the behavior of host sediment. SEM analysis shows the morphology of the sediments, which can affect the mechanical properties of the hydrate-bearing sediments. These properties can become the main parameters to consider for the design of suitable and economic dissociation techniques for gas hydrates formed in sediments.

Morphology identification of gas hydrate from pointwise Lipschitz regularity for P- and S-wave velocity

The accurate morphology identification of gas hydrate-bearing sediments (GHBS) has great significance in practical exploitation and subsequent resource evaluation. Previous studies have disclosed two main morphologies for gas hydrate in sediments: pore- and fracture-filling. However, the existing identification methods of gas hydrate’s morphology rarely consider their intrinsic differences in distribution characteristics. In this paper, a new method is proposed to identify the morphology of hydrate according to the scattered distribution of fracture dips for fracture-filling GHBS. Firstly, numerical simulations are performed to study the relationships between the morphology of hydrate and the sonic velocities. Considering the dip variation is within a certain range for fracture-filling hydrate, the theoretical curves show that the resulting mutation degrees between P- and S-wave velocities are inconsistent in fracture-filling GHBS, which is different from pore-filling GHBS. Then the modified estimation method for pointwise Lipschitz exponent α is introduced to capture their differences. The cross plots of Lipschitz exponent for P-wave velocity, α(Vp), and Lipschitz exponent for S-wave velocity, α(Vs), indicate that most of the dots representing pore-filling GHBS are evenly distributed near the line α(Vp)=α(Vs), while the dots representing fracture-filling GHBS are scattered outside the line α(Vp)=α(Vs). Based on these characteristics, a ratio method is put forward to differentiate the two types of hydrate. These hypotheses and methods are verified using the measured P- and S-wave velocities log data at different sites in Leg 204, Ocean Drilling Program (ODP), in the United States. Finally, the results of this new method agree closely with core data.

Concurrent decomposition and replacement of marine gas hydrate with the injection of CO2-N2

• CO 2 -N 2 was injected into gas hydrate sediments under real reservoir conditions. • Concurrent CH 4 hydrate decomposition and CO 2 -N 2 replacement occurs distinctly. • Local non-equilibrium with a higher CH 4 concentration leads to a local replacement. • Both of decomposition and replacement contributes to gas recovery. • Dual production pattern combines advantages of depressurization and replacement. CO 2 replacement has been regarded as a promising method for the recovery of gas hydrate. The kinetics and feasibility of its application to gas hydrate reservoir are extensively studied at low temperatures that are proper for the formation of CO 2 /N 2 hydrates. However, in facts, most of the gas hydrate reservoirs in marine sediments have relatively high temperature conditions that are below the hydrate equilibrium line of CO 2 /N 2 . In this work, CO 2 -N 2 gas was injected into gas hydrate sediments under the pressure–temperature conditions of real marine hydrate reservoirs to evaluate the kinetic behavior of the CO 2 -N 2 replacement at relatively high temperatures. It was observed that the CH 4 production was more prominent than the sequestration of CO 2 -N 2 . The results indicate that concurrent decomposition and replacement occur distinctly in gas hydrate reservoir with relatively high temperatures after the injection of CO 2 -N 2 . It is proposed that the local non-equilibrium with a higher concentration of CH 4 near the dissociating hydrate surface than that of the bulk gas phase can lead to a local CO 2 -N 2 replacement. The contribution of decomposition and replacement to gas recovery varies with the temperature and pressure conditions. Higher temperature and lower pressure would promote the decomposition and inhibit replacement, enhancing the gas recovery efficiency. This dual production pattern combines the advantages of both depressurization and replacement, which would substantially improve the safety of depressurization method for weak hydrate reservoir conditions in efficient gas recovery as the geologic storage of CO 2 -N 2 in hydrate form consolidates the sediments. These findings extend the previous knowledge on CO 2 replacement method and provide insights for a complete understanding of the application of this method to the real marine gas hydrate reservoirs.