Gas Production Behavior Research Articles

Numerical analysis of the gas recovery performance in hydrate reservoirs with various parameters by stepwise depressurization

Natural gas hydrates have drawn worldwide attention as a significant clean energy source in the 21st century. Depressurization is known to be the most effective method for hydrate exploitation owing to its feasibility and economic benefits. Recently, stepwise depressurization has received extensive attention owing to its advantages of effective prevention of ice generation and hydrate reformation during gas recovery. In this work, we optimized the 2-D simulator to model the evolution of temperature, pressure, hydrate saturation, and gas production behavior in hydrate sediments during decomposition process via stepwise depressurization. The effect of various reservoir characteristics on gas production was analyzed by introducing the sensitivity factor. The results demonstrated that higher specific heat capacity of the reservoir would promote gas production in the early stage of the reaction; however, this effect is reversed in the later stage. A higher thermal conductivity of the hydrate cores can dramatically enhance the gas production rate; however, this advantage is weakened with increasing thermal conductivity. Reducing the gas relative permeability hinders the hydrate decomposition process, and the water relative permeability has minimal effect on gas production. Based on the sensitivity analysis, the thermal conductivity and gas relative permeability are the main factors affecting hydrate decomposition. • Numerical simulation of gas production by step-wise depressurization is presented. • Higher thermal conductivity enhanced gas production via stepwise depressurization. • Gas permeability and thermal conductivity are main factors of gas recovery.

Laboratory Study on Hydrate Production Using a Slow, Multistage Depressurization Strategy

Optimization of the depressurization pathways plays a crucial role in avoiding potential geohazards while increasing hydrate production efficiency. In this study, methane hydrate was formed in a flexible plastic vessel and then gas production processes were conducted at constant confining pressure and constant confining temperature. The CMG-STARS simulator was applied to match the experimental gas production behavior and to derive the hydrate intrinsic dissociation constant. Secondly, fluid production behavior, pressure-temperature ( P ‐ T ) responses, and hydrate saturation evolution behaviors under different depressurization pathways were analyzed. The results show that integrated gas-water ratio (IGWR) decreases linearly with the increase in depressurizing magnitude in each step, while it rises logarithmically with the increase in the number of steps. Under the same initial average hydrate saturation and the same total pressure-drop magnitude, a slow and multistage depressurization strategy would help to increase the IGWR and avoid severe temperature drop. The pore pressure rebounds logarithmically once the gas production is suspended, and would decrease to the regular level instantaneously once the shut-in operation is ended. We speculate that the shut-in operation could barely affect the IGWR and formation P ‐ T response in the long-term level.

Numerical investigation on the long-term gas production behavior at the 2017 Shenhu methane hydrate production site

In 2017, an offshore methane hydrate production test was successfully conducted at well SHSC-4 in the Shenhu Area of the South China Sea, but the long-term gas production behavior is still unknown and requires further investigation. In this study, a multi-layered methane hydrate reservoir model with three sublayers of the hydrate-bearing layer (HBL), three-phase layer (TPL), and free gas layer (FGL) was built based on the actual geological conditions at this site, and a short-term simulation was initially conducted to verify the validity of the reservoir model. Afterwards, the long-term simulations were conducted to predict the hydrate dissociation and gas production behaviors in the reservoir and investigate the contributions of each sublayer to the total gas production, and the effects of the intrinsic permeability of each sublayer on the gas production were fully examined. The simulation results indicated that the average gas production rate (1.83 × 103 ST m3/d) was less than half of that confirmed during the 2017 Shenhu production test (5.15 × 103 ST m3/d). The majority of the total gas production originated from the free gas in the FGL (56.5%), followed by the methane gas released from hydrate dissociation in the HBL (24.1%), and the TPL contributed the least to the gas recovery (19.4%). In addition, if the method of permeability enhancement was applied to the methane hydrate reservoir at well SHSC-4, the gas production could be greatly promoted, but the mechanisms were different. Finally, the following application priority was recommended: HBL > FGL > TPL.

Permeability change induced by dissociation of gas hydrate in sediments with different particle size distribution and initial brine saturation

Permeability is critical to understand gas production behavior from hydrate reservoirs. The effects of particle size distribution and initial brine saturation on effective permeability of hydrate-bearing sediment during hydrate dissociation are poorly understood. In this study, X-ray CT imaging and Lattice Boltzmann simulations are combined to obtain a better understanding of sediment permeability changes during hydrate dissociation and the effects of particle size distribution and initial brine saturation. The results reveal that the dissociation of hydrate induced by depressurization starts from the part in contact with gas, causing a gradual increase in sediment effective permeability with decreasing hydrate saturation. When a critical hydrate saturation below 0.1 is reached, a sharper increase in permeability is found in sediments initially saturated with 50% brine than with 100% brine. To investigate the underlying relationship between hydrate morphology and sediment permeability, two topological parameters of an isolated hydrate cluster, equalivalent diameter and shape factor, are introduced. Phase topology analysis of hydrate clusters confirms that the partial water saturation method causes a more heterogeneous spatial distribution of hydrate at pore-scale. It also suggests that sediment with a narrower particle size distribution shows a faster increase in permeability and a more uniform hydrate morphology evolution with dissociation, no matter whether it is initially 50% or 100% brine saturated. A slower effective permeability increase and hydrate morphology evolution are achieved in initially 100% brine-saturated sediments, implying a more uniform dissociation of hydrate in pore space.

Carbothermal reduction of LiFePO4/C composite cathodes using acid-washed iron red as raw material through carboxylic acid pyrolysis reducing gas participation strategies

The study on the gas production behavior and pyrolysis kinetics of citric acid and tartaric acid provides a new idea for the researchers to choose a certain carboxylic acid. The results of TG-FTIR, TG-MS and kinetics research show that, compared with tartaric acid, the activation energy required for citric acid pyrolysis is lower, and more reducing gas (CO) can be produced, which is more suitable for use as a reducing agent. Therefore, we used citric acid, acid-washed iron red, Li2CO3 and NH4H2PO4 as raw materials to synthesize LiFePO4/C cathode materials by carbothermal reduction method. Through XRD, SEM and electrochemical measurements, it was found that the optimal calcination temperature of LiFePO4/C synthesis was 650 °C, the optimal mass ratio of citric acid to pickling iron red was 0.4:1, and the discharge capacity of the first cycle of the sample reached 120 mAh g−1 at 0.1 C, after 50 cycles, the discharge capacity of 122 mAh g−1 remained. This fundamental study provides a basic insight about the citric acid and tartaric acid pyrolysis, which is a new idea to supplement the evidence for the choice and application of carboxylic acid about reduce reaction.

Evaluation of the gas production enhancement effect of hydraulic fracturing on combining depressurization with thermal stimulation from challenging ocean hydrate reservoirs

The stimulation of hydraulic fracturing on a combination of depressurization with thermal stimulation for natural gas hydrate (NGH) exploitation from challenging ocean hydrate reservoirs is investigated in this study. The influence of fracture permeability, well spacing on hydrate exploitation, and the enhancement effect of hydraulic fracturing on different well spacing are numerically investigated. The results show that the hydraulic fracturing has a significant improvement on hydrate exploitation performance, including hydrate decomposition behaviour, gas production behaviour, gas recovery ratio, and energy ratio. This improvement enhances with the increase of fracture permeability, but the corresponding rate of increase gradually decreases. Gas production performance is extremely sensitive to well spacing. An extremely low gas production volume, gas recovery ratio and energy ratio will be obtained when well spacing is excessive. The existence of fracture can increase the effective well spacing. After fracturing, the gas production performance of each well spacing are significantly improved and this improvement performs better with larger well spacing.

Enhanced gas production by forming artificial impermeable barriers from unconfined hydrate deposits in Shenhu area of South China sea

The absence of impermeable overburden and underburden layers makes it difficult to develop the unconfined hydrate deposits. Using numerical simulation method, the hydrate dissociation and gas production behaviors are fully investigated during depressurization in Shenhu Area based on the available geological data. Results show that depressurization cannot result in significant pressure drop due to the presence of permeable boundaries, which leads to low gas production rate but excessive water production. To overcome these disadvantages, the method of forming artificial impermeable barriers by injecting gels in the permeable overburden and underburden is proposed in this work. Moreover, the effect of the radius of artificial impermeable barriers on gas production is analyzed numerically. Simulation results show that the artificial impermeable barriers prevent large amounts of seawater from entering the production well during the depressurization process, which significantly enhances the depressurization effect, and thus promotes hydrate dissociation and gas production. By forming the 90-m artificial impermeable barriers, the hydrate dissociation percent is greatly enhanced from 8.9% to 45.4%, the cumulative CH4 production volume is increased from 4.46 × 106 ST m3 to 1.06 × 107 ST m3, while the average water production rate is remarkably decreased from 1412 m3/d to 360 m3/d.

Comprehensive modeling of multiple transport mechanisms in shale gas reservoir production

A boom in the production of shale gas has recently impacted the world’s energy supply. The hydraulic fracturing technology has been widely used in the development of shale gas reservoirs. Models for accurate reservoir simulation are essential for their economic production. In this paper, a model for shale gas reservoir production is proposed to account for slip flow, Knudsen diffusion, surface diffusion, gas adsorption/desorption, stress dependence of a pore structure, a non-ideal gas effect, and a flow mechanism difference between organic and inorganic content in the shale matrix. This model is implemented in our in-house simulator with a coupled MINC-EDFM approach to study and predict shale gas production behavior. Comprehensive sensitivity studies are performed to analyze the importance of different parameters in shale gas production. These parameters are divided into two categories. The first category includes reservoir data, such as shale matrix porosity, a nanopore radius, an organic/inorganic volume ratio, hydraulic fracture half-length, and fracture spacing. The second category includes parameters relevant to flow mechanisms, such as a non-ideal gas effect, stress dependence, presence of an adsorbed layer as well as a selection of a flow mechanism model. It is found that parameters related to hydraulic fractures impact calculated gas production more than reservoir matrix data. Among the fracturing parameters, hydraulic fracture half-length has a stronger effect than fracture spacing, and among matrix properties, porosity has a larger impact than a nanopore radius or the assumed organic/inorganic content ratio. These results help to optimize a shale gas reservoir production design. In addition, in a synthetic case assuming a 1 nm pore radius, the presence of an adsorbed gas layer has a more tremendous effect compared to the non-ideal gas and stress dependence phenomena. Moreover, the developed simulator with the multiple transport mechanisms can be used to accurately predict shale gas reservoir production. The findings of this study help a better understanding of shale gas flow and can be used to enhance the production of shale gas reservoirs.

Study of gas sorption, stress effects and analysis of effective porosity and permeability for shale gas reservoirs

The gas sorption capacity, effective porosity, and effective permeability are important to shale gas reservoir characterization, gas-in-place estimation, and production behavior prediction. Previous studies have ignored the absorption gas in gas sorption measurements; however, the absorption gas is dissolved into kerogen and cannot be underestimated. In this study, experiments are performed on shale samples to quantify the gas sorption capacity with new sights and to analyze the effective porosity and permeability in adsorbed and absorbed gas considering gas sorption and stress impacts. Then, data are also obtained for quantitative analysis. This study revealed that the proposed gas sorption model (sum of adsorption and absorption of gases) is as accurate as the Langmuir model. Based on this model, converted excessive to absolute gas sorption and the contribution of the absorption gas to the total gas sorption are estimated. The porosity and permeability in adsorbed/absorbed and sorption gas increases with increasing pore pressure, whereas the effective porosity and permeability decreases with increasing pore pressure. The effective porosity is affected more at low pressure, whereas it is almost the same or changes slightly at higher pressure; however, the effective permeability is dependent on the adsorbed porosity. The amount of absorbed gas increases linearly with increasing pore pressure, and that it followed Henry's law, whereas the effective absorbed porosity decreases linearly with increasing pore pressure. The effective absorbed permeability increases at a lower rate at low pressure, while at a high pressure, the rate of increase is higher. It is also observed that the adsorbed/absorbed porosity, such as gas sorption, is a function of the total organic carbon and specific surface area. However, both parameters vary with kerogen quality. The combined impact of gas sorption and stress may change the controlling factors of shale gas properties and enable the accurate measurement of the effective porosity and permeability.

Effect of permeability anisotropy on depressurization‐induced gas production from hydrate reservoirs in the South China Sea

AbstractThe permeability anisotropy (ie, horizontal, kr, to vertical, kz, permeability ratio) of gas hydrate reservoirs may be a significant factor that affects hydrate dissociation and gas production. Here, site SH2, a candidate for field testing comprising a clayey silt gas hydrate reservoir in the Shenhu area in the South China Sea, was chosen to investigate the effect of permeability anisotropy on gas production behavior through numerical simulations. The spatial distribution of physical fields (ie, pressure, temperature, and saturation) and the evolution of gas and water recovery are comparatively analyzed. The simulation results show that permeability anisotropy has a significant impact on gas extraction, especially when the horizontal permeability is higher than the vertical one. The sensitivity analyses indicate that permeability anisotropy in both medium‐permeability (10‐100 mD) and low‐permeability (1‐10 mD) sediments are conducive to hydrate dissociation and that a higher horizontal permeability is more favorable for gas production. Comparatively, permeability anisotropy in low‐permeability sediments is not beneficial for improving production efficiency. In addition, our work also suggests that heterogeneous hydrate saturation in a reservoir‐scale model should be employed in future predictions because the gas production potential will be overestimated in a homogeneous reservoir under the same conditions. These findings contribute to a clear understanding of the influence of reservoir properties on gas hydrate dissociation processes and provide a reference for future field trials and commercial production.

Controls on Gas Domains and Production Behaviour in A High-Rank CSG Reservoir: Insights from Molecular and Isotopic Chemistry of Co-Produced Waters and Gases from the Bowen Basin, Australia

This paper uses hydrochemical and multi-isotope analysis to investigate geological controls on coal seam gas (CSG) saturation domains and gas well production performance in a high-rank (vitrinite reflectance (Rv) > 1.1) CSG field in the north-western Bowen Basin, Australia. New hydrochemical and stable isotope data were combined with existing geochemical datasets to refine hypotheses on the distribution and origins of CSG in two highly compartmentalized Permian coal seams. Stable isotopic results suggest that geographic variations in gas content, saturation and production reflect the extent of secondary microbial gas generation and retention as a function of hydrodynamics. δ13C and δ2H data support a gas mixing hypothesis with δ13C-CH4 increasing from secondary biogenic values to thermogenic values at depth (δ13C −62.2‰ to −46.3‰), whereas correlated methane and carbon dioxide carbon isotope compositions, Δ13C(CO2–CH4) values and δ13CDIC/alkalinity trends are largely consistent with microbial CO2 reduction. In addition, below 200 m, the majority of δ13C-CO2 values are positive (δ13C: −1.2‰ to 7.1‰) and δ13CDIC shows an erratic increase with depth for both seams that is characteristic of evolution via microbial activity. The progression of carbon isotope values along the CO2 reduction fractionation line suggests progressive depletion of the CO2 reservoir with increasing depth. Faults clearly segment coal seams into areas having significantly different production, with results of geochemical analysis suggesting that pooling of biogenic gas and waters and enhanced methanogenesis occur north of a faulted hinge zone.

Gas production behavior from hydrate-bearing fine natural sediments through optimized step-wise depressurization

There have been several field tests around the world to recover natural gas from gas hydrate reservoirs, yet they mostly suffer from the low productivity, sand problems and poor economic efficiency. The ultralow permeability of the sediments and an insufficient heat supply act as major barriers. Intense investigations have been carried out to study the gas production behavior from lab-synthesized hydrate-bearing coarse sands; yet the porous matrices could differ significantly from the natural sediments. Few studies have been found to focus on the role of fine natural sediments in the gas recovery performance. In this study, natural marine sediments from the South China Sea are used as the porous matrices, and gas is produced through an optimized stepwise depressurization. Significant differences in the gas production behaviors from fine natural sediments and coarse grains are found. The fine marine sediments may induce the blockage of the production well, even with protection measures; this problem will result in an uncontrolled pressure drop and gas output. Moreover, the stepwise depressurization efficiently contributes to remitting the temperature drop of the reservoir, increasing the minimum temperature from −0.5 ℃ upon a straight pressure drop to 0.27 ℃ upon a step-wise depressurization. This method can therefore help prevent the ice generation during hydrate dissociation. Additionally, a finer pressure gradient of 0.5 MPa will enhance the hydrate dissociation rate by 18.92% compared with the 2 MPa step scenario. The average gas production rate is determined to positively correlate with the Stefan number, which indicates a dominant role of the sensible heat of the reservoir in the efficient gas production. The findings could be applied in the field tests of gas hydrates to avoid ice generation and achieve a stable and continuous gas production behavior.

3D visualization of methane hydrate production behaviors under actual wellbore conditions

This study aimed to give a better visualization of the hydrate dissociation and gas production behaviors during methane hydrate production under actual wellbore conditions via 3D images. A real 3D methane hydrate reservoir model was built in this study, and three different types of production methods using horizontal wells (depressurization or hot water injection) were designed. Meanwhile, the gas production and fluid flow behaviors under actual wellbore conditions were revealed through 3D visualization. The simulation results indicated that for the depressurization scenario, the pressure loss in the wellbore mainly affected gas production at the early stage of the depressurization process, while the effect on the long-term gas production behavior was not quite significant. However, for the hot water injection scenario, the heat and flow losses in the wellbore both had great influence on the gas production and fluid flow behaviors, which would cause the decrease in gas production and have a negative impact on the processes of heat transfer, hydrate dissociation, and gas-liquid two-phase flow in the reservoir. Especially, at the end of 1.5 yr, the decrease in total gas production caused by the flow loss (19.4%) was much larger than that caused by the heat loss (4.1%). Therefore, for the future field trials and further investigations on 3D visualization of the actual methane hydrate production process, such losses in the wellbore should be taken into account for the accurate prediction of the long-term gas production behavior.

Experimental and modeling study of the stress-dependent permeability of a single fracture in shale under high effective stress

It is of great importance to investigate the change in the permeability of stimulated shale gas reservoirs under high effective stress because the depths of producing shale gas reservoirs in China have gradually exceeded 3500 m. In this study, a series of permeability measurements were performed on two fractured Longmaxi shale samples under confining pressures from 5 to 80 MPa. Experimental results show that the measured apparent permeability of the fractured samples sharply decreases with effective stress. The intrinsic permeability of fractured shale decreases with increasing effective stress, and the Klinkenberg constant is almost invariable. Then, a stress-dependent fracture permeability model was derived based on the fracture compressibility models. The modeling results indicate that the permeability model derived in this study can accurately describe the experimental data, with errors of 5.63% and 2.24% for samples I and II, respectively. A comparison of the modeling results using this model to those using permeability models available in the literature indicates that the model derived in this study is preferable, especially for a broad effective stress range. Moreover, the average compressibility of fractured Longmaxi shale decreases from 0.077 to 0.014 MPa−1 with effective stress increasing from 4.13 to 79.65 MPa, showing that fracture compressibility is strongly stress-dependent. The results in this paper will be important for the prediction of permeability change and gas production behavior for the development of deep shale gas.

Pore connectivity and water accessibility in Upper Permian transitional shales, southern China

Abstract Pore connectivity of shale controls shale gas migration and production behavior. The pore connectivity and water accessibility in clay-rich Upper Permian transitional shales remain unclear. Contrast matching small-angle neutron scattering (CM-SANS) tests were used to determine the accessibility of water to pores in the transitional shales. Complementary analyses with SANS, gas (CO2 and N2) physisorption isotherm, mercury intrusion capillary pressure (MICP), helium ion microscopy (HIM), as well as field emission-scanning electron microscopy (FE-SEM) were conducted to study the pore connectivity and distribution characteristics of closed pores. The results show that closed pores (inaccessible to nitrogen molecules and mercury) are mainly distributed in pore diameters ＜10 nm and associated with organic pores and interlayer spaces of illite-smectite mixed-layer mineral. The pore volume values obtained from MICP and N2 adsorption underestimate the large pores (pore diameters ＞100 nm) in shales. Based on deuterated water CM-SANS tests, 87–98% of the pores (2–200 nm diameters) are water-connected in transitional samples. The low accessibility to water is at pore-sizes of 5–10 nm and 20–30 nm. Results from in-situ gas contents show that closed pores have a certain gas bearing capacity, but micropores (pore diameters ＜2 nm) control the gas occurrence in transitional samples. The connectivity of the organic pore network and between organic pores and surrounding interparticle pores is directly supported by FE-SEM and HIM imaging. Overall, improving pore-fracture connectivity through effective fracturing techniques is a means of mitigating the rapid decline in shale gas production.

Production performance and numerical investigation of the 2017 offshore methane hydrate production test in the Nankai Trough of Japan

Since the first offshore methane hydrate production test was conducted in the Nankai Trough of Japan in 2013, the second production test was also conducted at the same test site in 2017, but information about this field test is limited. Thus, in this study, we aimed to report detailed information about the 2017 production test for the first time, and conducted short-term simulations of the oceanic methane hydrate production from the multilayered reservoir models for model validation. Then, we predicted the long-term gas production behavior for a production period of 5 y, and investigated the effect of the production intervals on the processes of hydrate dissociation and gas production. The simulation results indicated that most of the released gas from hydrate dissociation was actually produced indirectly in the aqueous phase rather than directly in the gas phase, and the proper utilization of the packers on the wellbore could effectively promote gas production, but also caused excess water production. Therefore, high-performance gas-water separation devices and water production management are necessary for future production tests. Furthermore, the 5-y average gas production rates for each case designed in this study were estimated as 1.01 × 104–1.21 × 104 ST m3/d, which were far less than the commercial exploration level of 3.0 × 105 ST m3/d, so improvements in the production strategies should be considered for future production tests.

Steam gasification of biochars derived from pruned apple branch with various pyrolysis temperatures

In this study, the gas production behavior from the steam gasification of the biochar derived from the pruned apple brunch was investigated using a fixed-bed reactor. The optimal biochar obtained at the pyrolysis temperature of 550 °C was gasified under different operating conditions for the hydrogen rich gas production. The experimental results indicated that high reaction temperature and high water flow rate were both beneficial to the hydrogen gas yield, but excess steam had a negative impact contrarily. Besides, the small size particles (0.5–1.0 mm) showed better performance in the hydrogen gas production at the low water flow rates (0.05–0.20 g/min); while the large size particles (1.0–2.8 mm) showed better performance at the high water flow rates (0.25–0.30 g/min). The suitable operating conditions for the gasification of the biochar were determined as the reaction temperature of 850 °C, water flow rate of 0.25 g/min, and particle size of 1.0–2.8 mm.

The status of exploitation techniques of natural gas hydrate

Abstract Natural gas hydrate (NGH) has been widely considered as an alternative form of energy with huge potential, due to its tremendous reserves, cleanness and high energy density. Several countries involving Japan, Canada, India and China have launched national projects on the exploration and exploitation of gas hydrate resources. At the beginning of this century, an early trial production of hydrate resources was carried out in Mallik permafrost region, Canada. Japan has conducted the first field test from marine hydrates in 2013, followed by another trial in 2017. China also made its first trial production from marine hydrate sediments in 2017. Yet the low production efficiency, ice/hydrate regeneration, and sand problems are still commonly encountered; the worldwide progress is far before commercialization. Up to now, many gas production techniques have been proposed, and a few of them have been adopted in the field production tests. Nevertheless, hardly any method appears really promising; each of them shows limitations at certain conditions. Therefore, further efforts should be made on the economic efficiency as well as sustainability and environmental impacts. In this paper, the investigations on NGH exploitation techniques are comprehensively reviewed, involving depressurization, thermal stimulation, chemical inhibitor injection, CO2–CH4 exchange, their combinations, and some novel techniques. The behavior of each method and its further potential in the field test are discussed. The advantages and limitations of laboratory studies are also analyzed. The work could give some guidance in the future formulation of exploitation scheme and evaluation of gas production behavior from hydrate reservoirs.

Analyzing the process of depressurization-induced gas production from natural marine sediments

Though understanding the gas production behavior from methane hydrate in sediments by depressurization are critical for the utilization of gas hydrate resource and has been widely studied, very few researches are reported using natural marine sediments as porous matrices. Significant differences have been found between the natural sediments and widely used coarse sands; difficulties could be commonly encountered in the formation and production process arising from the fine grain sizes and thereby low permeability. In this work, gas production behavior in hydrate-bearing natural marine sediments from the South China Sea was investigated by depressurization with different gas production pressures (2 MPa, 3 MPa and 4 MPa)and pressure gradients (1 MPa, 2 MPa and 4 MPa). Results show that the gas production process consists of two main stages: the rapid free gas liberation stage when the pressure and temperature drop quickly; the hydrate decomposition stage when the gas production slows down and temperature remains relatively stable and then rises to the backpressure driven by heat transfer from the ambient. A high pressure gradient and low production pressure were found to efficiently facilitate the gas production process. The minimum temperature during production significantly varies, under the combined effects of fast gas release and hydrate decomposition, which could play a crucial role in the production behavior. Furthermore, the difference in the thermal conductivity of the natural marine sediments with common coarse grains seriously affects the heat transfer and gas production behavior, with heat transfer from the ambient to the production well with a radial temperature gradient. The inhomogeneity of hydrate saturation vertically resulting from the low permeability of natural sediments also results in a non-uniform temperature distribution during production, which could locally trigger the secondary hydrate formation and freezing thereby hindering the gas production. Therefore, significant differences could be present in the natural sediments, making this work helpful in understanding the production behavior from natural hydrate deposits.

Enhancement of gas production from methane hydrate reservoirs by the combination of hydraulic fracturing and depressurization method

The combination of hydraulic fracturing and depressurization method has been proposed to enhance gas production efficiency from methane hydrate (MH) reservoirs. To evaluate the efficacy of this method, we construct a fractured MH reservoir model and investigate by means of numerical simulation the gas production behaviors under two different temperature conditions. The simulation results indicate that the combination of hydraulic fracturing and depressurization method is more efficient for gas production than the single depressurization method. For the high-temperature reservoir, the hydrate dissociation and gas production during the early depressurization stage can be significantly enhanced after fracturing, and the effect of increasing the size and permeability of the fractured zone on gas production rate is more remarkable in the early depressurization stage than in the late depressurization stage. For the low-temperature reservoir, while the improvement in hydrate dissociation and gas production by fracturing is dramatic during the entire depressurization period, the increment in total gas production is very low in absolute terms. In addition, gas production from low-temperature reservoir is very sensitive to initial temperature, and increasing the reservoir temperature can enhance the benefits of fracturing.