Sand production has become a common phenomenon in the exploitation of unconsolidated natural gas hydrate reservoirs, which will hinder the long-term production of natural gas hydrate reservoirs. However, there are few literatures reported on the influences in reservoir physical properties such as permeability and porosity, and production laws caused by sand production. This paper provides a numerical model, coupled with reservoir sand-gas-water multiphase flow processes, which is capable to simulate the process of sand production in natural gas hydrate reservoirs. The simulation results indicate that sand settlement is mainly concentrated near the wellbore due to the high concentration of migrated sand. The decrease in reservoir porosity and permeability caused by sand settlement has a significant impact on production. The impact of sand production on reservoir fluid fluidity shows that fluid flow is inhibited near the wellbore, while fluid flow performance increases far away from the wellbore. The numerical model and analysis presented here could provide useful insight into changes in reservoir physical properties and production laws caused by sand production in the natural gas hydrate-bearing marine sediments using depressurization method.
Natural gas hydrate (NGH) is an ice-like solid compound formed by natural gas (the main component methane) and water under high-pressure and low-temperature conditions [
The northern slope of the South China Sea is a hot area for research on gas hydrate exploration and test production in China [
The research on sand production in hydrate reservoirs mainly focuses on the prevention of sand production wellbore and the study of overall sand migration in the hydrate reservoir. Experts and scholars have put forward many suggestions based on their own research results. Li et al. and Cao et al. believe that the secondary formation of hydrates and clay accumulation on the sand control medium are the key to clogging [
Considering three phases: vapor-liquid-solid, and five components: natural gas hydrate, methane gas, water, solid sand, and migrating sand Sand has the same critical sand detachment speed in the natural gas hydrate layer Migrating sand flows with the fluid without changing the fluid properties Considering the influence of gravity and capillary force on gas and water seepage Solid sand does not occupy absolute porosity, while natural gas hydrates occupy absolute porosity
From the assumptions, it is known that the detachment of sand particles in the sediment depends on the flow rate of water. When the water velocity exceeds the critical sand detachment speed, the solid sand begins to move with the formation water to become mobilized sand.
General formula for sand detachment is expressed as
Concentration equation for sand detachment is expressed as [
Ensure the rationality of sand migration in fluid through mass conservation equation. The solute transport mass conservation equation is expressed as [
General formula for Sand sedimentation is expressed as
Concentration equation for sand sedimentation is expressed as [
The permeability changes of natural gas hydrate reservoirs depend on effective porosity. It is calculated as the ratio of volume of water and gas to total matrix volume. With natural gas hydrate decomposition, the volume of solid hydrate gradually decreases. Therefore, the effective porosity is also gradually increased, which is expressed as
The relationship between effective porosity and permeability is represented by the following equation:
According to 1 standard volume of natural gas hydrate decomposition, 164 standard volumes of gas can be released [
Natural gas hydrate decomposition equation is expressed as [
A natural gas hydrate simulator software CMG+STARS was used to simulate sand-containing natural gas hydrate reservoirs, which can be adopted to modeling the processes of natural gas hydrate production, such as natural gas hydrate decomposition, sand detachment, sand migration, sand sedimentation, and mass and heat transfer under complex situation of multiple components.
In this study, the multiphase flow natural gas hydrate model is established using the geological parameters of the natural gas hydrate reservoir in the Shenhu area of the South China Sea. The critical parameters of the model are shown in Table
Important model parameter.
Parameter | Value | Parameter | Value |
---|---|---|---|
Initial pressure |
10 MPa | Initial temperature |
13°C |
Initial natural gas hydrate saturation of natural gas hydrate sediment |
0.3 | Initial permeability |
3 mD |
Initial water saturation of natural gas hydrate sediment |
0.65 | Initial gas saturation of natural gas hydrate sediment |
0.05 |
Natural gas hydrate sediment thickness [ |
30 m | Initial porosity of natural gas hydrate sediment |
0.3 |
Depth | 1200 m | Bottom hole pressure | 3 MPa |
Over layer thickness | 15 m | Under thickness | 15 m |
Initial porosity of over/under layer | 0 | Initial sand concentration of natural gas hydrate sediment | 921.74 mole/m3 |
Schematic diagram of natural gas hydrate reservoir.
As a key parameter of the practical production data, cumulative gas production is an important basis for verifying the accuracy of the model. The simulated accumulative gas against measured data of the 2017 South China Sea production test are presented in Figure
Simulation results of cumulative gas production compared with field measured date from Shenhu pilot test.
It can be seen in Figure
Simulation results of gas production rate and sand production rate.
Gas production rate
Sand production rate
The influence in the natural gas hydrate reservoir mining process caused by sand production is mainly concluded in three stages, namely, sand detachment, sand migration, and sand sedimentation. Figure
Evolution of spatial distribution of solid sand concentration.
Evolution of spatial distribution of effective porosity.
Evolution of spatial distribution of permeability.
Variation of the sediment physical properties under different times.
Effective porosity
Permeability
Figure
Variation of the fluid mobility under different times.
Gas phase mobility
Water phase mobility
This paper establishes a numerical simulation model based on the South China Sea first offshore NGH production data to simulate the impact of sand production on reservoir physical parameters and production during natural gas hydrate reservoir exploitation by depressurization. Based on the modeling results, the following conclusions can be obtained:
In the process of gas hydrate depressurization production, when the reservoir sand meets the migration conditions, it migrates with the formation fluid to the wellbore. The concentration of migrating sand around the wellbore increases, resulting in sand settlement. Then, the porosity and permeability near the wellbore decrease, which in turn causes blockage of the formation, resulting in low production The simulation result shows that the evolution of spatial distribution of gas hydrate reservoir properties caused by sand settlement with time. The physical properties of the formation outside the range of sand settlement have no effect on the fluid and even increase the fluidity of the fluid. The range of formation blockage of natural gas hydrate reservoir at different times is considered for reservoir reformation, thus contributing to efficient and economical development Different types of natural gas hydrate reservoirs have different periods of formation blockage caused by sand settlement. The simulation results show that the reduced gas production rate is significantly affected by sand settlement near the wellbore about the 20th day of well start up, according to the South China Sea geological model. In view of the natural gas hydrate reservoirs in the South China Sea, stratigraphic reformation should be carried out around the 20th day after mining, so as to improve the formation seepage capacity
All results and data are in the manuscript.
The authors declared that there is no conflict of interest regarding the publication of this paper.
The project is supported by the National Natural Science Foundation of China (No.51974347, 51991364) and the Major Scientific and Technological Projects of CNPC under Grant ZD2019-184-002.