Gas-water Relative Permeability Research Articles

Experimental study on the drainage gas recovery of an environmentally friendly nanofluid in tight gas reservoirs

AbstractThe efficiency of gas recovery in tight gas reservoirs has been a challenge in the oil and gas industry for the past decade because conventional drainage or water‐controlled gas recovery technologies typically have poor performance in low‐permeability reservoirs. To solve this problem, self‐made nanofluid was introduced to enhance drainage gas recovery in a tight gas reservoir. In this paper, nanofluid was prepared by phase reversal technology for application in a tight gas reservoir. Its thermal, acidic, alkaline, and salty stabilities were systematically investigated by using light transmittance as a shortcut index. At the same time, its biodegradability and biotoxicity were evaluated based on the industry/national standard, and the effectiveness of its drainage gas recovery was studied by dynamic gas–water percolation. The results showed that the self‐made nanofluid can be effectively used for drainage gas recovery in tight gas reservoirs. The nanofluid has chemical stability and is environmentally friendly, which fully conforms to the contemporary development trend of the oil and gas industry. The nanofluid can shift the isotonic point of the gas–water relative permeability to the left (its minimum is 1.83% at 6.25 wt.% and maximum is 4.78% at 100 wt.%) and reduce the irreducible water saturation (its minimum is 8.84% at 6.25 wt.% and maximum is 4.28% at 100 wt.%), achieving the purpose of the enhancement of drainage gas recovery. The research results provide technical support for the application of nanofluid to improve the gas production in tight gas reservoirs.

Experimental study on the permeability jail range of tight gas reservoirs through the gas–water relative permeability curve

The permeability jail refers to a specific water saturation range in a tight gas reservoir, where almost no gas or water phase can flow effectively. In the process of drilling and fracturing, water saturation rises and falls into the permeability jail. To reduce or avoid falling into the permeability jail in the recovery process, a method for measuring gas–water relative permeability of tight sandstone is established here that considers salt sensitivity, gas slippage effect, stress sensitivity, and high bound water saturation. Then, the permeability jail range was determined to provide guidance and suggestions for field application. Considering a typical tight sandstone as an example, the proposed method was used to expand the measurement range of gas–water relative permeability and observe the permeability jail range, laying an experimental foundation for accurately determining the permeability jail range in a given formation. The Byrnes model can preliminarily predict the permeability jail range with accurate bound water saturation and residual gas saturation. When the permeability jail phenomenon occurs in the core, the larger the permeability is, the smaller the permeability jail range will be; and the larger the porosity is, the smaller the permeability jail range will be. When the permeability jail phenomenon occurs in the tight sandstone reservoir, the damage to the reservoir due to external fluid and solid phased particles should be strictly controlled. The damage is stronger, the permeability and porosity decline, and the permeability jail range is wider. Other gases or solvents can be used as fracturing fluids to minimize formation damage.

Experimental evaluation of the dynamic water-blocking effect in coalbed methane reservoir

Field observations indicate that almost 59% of coalbed methane (CBM) wells in the southern Qinshui Basin showed insufficient daily gas production (∼600 m3/t); this is caused by the water-blocking effect (WBE) attributed to the invasion of fracturing fluids or the accumulation of formation water. WBE can cause serious damages to the low-permeability reservoir but has not been paid sufficient attention to in CBM studies. To enhance understanding of the dynamic WBE in the multiphase flow process, we conducted core flooding experiments on two typical Chinese bituminous coal and anthracite coal samples. During the flooding experiments, real-time nuclear magnetic resonance (NMR) measurements of the change of water signal in the core were used to calculate the gas-water relative permeability and to evaluate the dynamic WBE. The results highlight that a more pronounced WBE occurred in anthracite coal compared with bituminous coal. The gas breakthrough model can calculate the gas breakthrough time, which is a useful parameter for evaluating water blocking. The water-blocking threshold pressure gradient (TPG) was determined based on experimental data. The results reveal that the water-blocking TPGs for both samples follow a positive power-law relationship with the normalized water saturation. The water-blocking TPG is approximately an order of magnitude higher than that of the conventional gas TPG. A high water-blocking TPG value reflects stronger gas/water interference during multiphase flow, exerting a negligible impact on the gas migration through the coalbed, which should be prioritized in CBM production. The implications of this study are important for a better understanding of the interaction mechanism of gas and water transport in coal reservoirs during the gas production process.

Experimental Study on Gas–Water Relative Permeability Characteristics of Tight Sandstone Reservoir in Ordos Basin

Accurate measurement of relative permeability curve is the basis for evaluating gas reservoir performance. The unsteady-state method could bring significant measurement error for low-permeability cores. However, it is difficult to control the constant gas flow rate in the traditional steady-state method, which obstacles the experimental operation. In this study, an improved steady-state method was proposed. First, the pressure value obtained from the experiment, when the gas permeability no longer changed with the average pressure on the rock core, was set as the testing pressure. Then, the gas was injected under constant pressure, and the water was injected with a constant flow rate. Finally, the relative permeability values of gas and water phases were calculated based on Darcy’s law. Comparative analysis of the results of the relative permeability curves under formation pressure and pressure with negligible slip effect indicates that the relative permeability curves are the same in gas and water phases, proving the feasibility of the new method. Further, the results were compared with those of the test method at normal pressure, the water-phase relative permeability showed no significant change, the relative permeability of gas phase was larger, the two-phase flow area became wider, and the irreducible water saturation was lower than that at the normal pressure. This result reflects that pressure does not significantly affect the flow of wetting phase but tremendously influences the nonwetted phase under low pressure. The relationship between relative permeability and water saturation is linear in the semilogarithmic coordinate diagram and can be described by using the following relationship: ln k rg / k rw = a S w + ln b . With the decrease in the core permeability, relative permeability curve, and isotonic point moved to the right, irreducible water saturation gradually increased, and residual gas saturation decreased, indicating that the smaller permeability induced a lower gas-phase flow capacity.

Image-based pore-network modeling of two-phase flow in hydrate-bearing porous media

Natural gas hydrate (NGH) has been widely regarded as a future strategic alternative energy resource. Permeability is crucial to produce gas effectively from NGH reservoirs. Experimentally studying the hydraulic characteristics of hydrate-bearing porous media, especially for two-phase flow, is difficult due to the rigorous stable conditions of NGH. In this work, the 3D porous structure and NGH distributions of a synthetic sample with a hydrate saturation of 52.43% are first obtained by using μCT scanning. Then, the hydrate saturation is numerically increased and decreased to generate nine extra hydrate-bearing samples, which cover a wide saturation range from 5.53% to 67.26%. Finally, a quasi-static pore-network model is used to study the effects of hydrate saturation on the absolute permeability and gas–water relative permeabilities of hydrate-bearing porous samples. The numerical algorithm of generating hydrate-bearing samples can well mimic the realistic morphology and distributions of hydrate in porous media. Hydrate saturation remarkably influences the pore-size distribution and connectivity of pore spaces. The relationship of absolute permeability and hydrate saturation, which qualitatively matches experimental data, is fitted. Moreover, gas relative permeability decreases as hydrate saturation increases.

Relative permeability of gas and water flow in hydrate-bearing porous media: A micro-scale study by lattice Boltzmann simulation

The water-gas relative permeability is an important parameter to characterize multiphase flow in sediments. To study the water-gas relative permeability of hydrate-bearing porous media, multiphase flow simulations were carried out at the pore scale using the lattice Boltzmann method. The effects of hydrate saturation and hydrate-growth habits on the water-gas relative permeability, which is scaled by the relative permeability considering the hydrate only, were evaluated in a two-dimensional porous medium. Results show that the increase of hydrate saturation causes the decrease of water-gas effective permeability as expected. However, the effect of hydrate saturation on the water-gas relative permeability is different from that of hydrate saturation on the water-gas effective permeability. The water-gas relative permeability increases with the increase of hydrate saturation in the pore-filling case. The water-gas relative permeability decreases with the increase of hydrate saturation in the grain-coating case. The wettability of solid phase has a different effect on the relative permeability of wetting phase and nonwetting phase. The Jamin effect (phase blocking) was observed and may exist in the production of gas from natural gas hydrate reservoirs. This seriously affects the multiphase flow characteristics. The changes of microscale fluid distribution effect the changes of water-gas relative permeability. The relationship between the water-gas relative permeability and the characterization parameters of microscale fluid distribution was analyzed.

Productivity model with mechanisms of multiple seepage in tight gas reservoir

The productivity model with unilateral threshold pressure gradient, real gas effect or non-Darcy effect has been documented in the research of tight gas reservoir. However, the multiple seepage mechanisms are poorly addressed in a productivity model, especially the application of gas-water relative permeability curve changing with the displacement pressure. A novel productivity model of multi-stage fractured horizontal wells with mechanisms of multiple seepage was proposed the present study. Results show that the stress effect has a negative effect on the effective permeability, while the Knudsen diffusion effect of gas has a positive effect. The water flow can inhibit the gas flow in the tight gas reservoir, whose effect is more significant with larger displacement pressure differences. The higher initial water saturation and reservoir temperature, whereas the lower gas well productivity, contribute to a high gas well productivity in the reservoir of high pressure.

Influence of different shut-in periods after fracturing on productivity of MFHW in Duvernay shale gas formation with high montmorillonite content

Drilling multi-stage fracturing horizontal wells (MFHWs) is the most effective way to unlock shale gas resources economically. This paper investigates the influence of different shut-in periods after fracturing, and their impact on the productivity of MFHWs in the Duvernay shale gas formation. This western Canadian formation has a high montmorillonite content which impacts the findings. A Duvernay shale core with high montmorillonite content was used to study gas–water relative permeability. Unsteady state tests were conducted under a variety of soaking times. The experiments demonstrated that the Permeability Jail for relative permeability curves exist in a water saturation range of 60% – 80%. This phenomenon partly explains the rapid gas production decline and a long period of little water production during the formal production in a typical shale gas well. Clay in shale mainly contains illite and montmorillonite. They have surface hydration, which occurs fast enough to cause induced fractures that improves the seepage capacity initially when the core is soaked. As the soaking time prolongs, there is an osmotic hydration expansion of the montmorillonite blocking pore throats and a corresponding reduction of the seepage capacity. The relative permeability increases during the soaking days one to four. After four soaking days, relative permeability begins to slowly decrease over time. Study calculations found that 61.4% – 75.6% of the total fracturing fluid filtrates into the formation. During days one to six of the soaking, the filtration volume increases significantly due to a high initial pressure in the fractures after pump shutdown. After seven days of soaking, the filtration velocity decreases due to the pressure drop and the difficulty of compression caused by more and more fluid in the formation. Based on reservoir simulations of 600 days, the relative permeability value in the near fracture zone and the cumulative gas production are the greatest on day four of the shut-in. The longer the shut-in period, the greater the initial water production rate and cumulative water production reaching a maximum at four shut-in days. In this Duvernay area with high montmorillonite content, the optimal shut-in period after fracturing was determined to be four days.

Relative permeability measurement of coal microchannels using advanced microchip technology

The gas–water flow in coal cleats is an important factor affecting coalbed methane production. However, difficulties are often encountered in the prediction of gas production. Limited understanding of two-phase flow behaviour in microchannels reduces prediction accuracy, often leading to overestimation. In this study, based on micro-computed tomography, advanced microchip technology is used to predict the optimal coal cleat in the polydimethylsiloxane chip. Gas and liquid injection experiments are carried out on the microchannels through the syringe pumps, as the two-phase flow morphology in the system can obtain flow information that cannot be provided by conventional laboratory measurements. The flow capacities of single-phase gas, water, and wetting liquid in the microchannels are compared, alongside determining the flow laws under different wettability and flow rates. The results show that in the single-phase fluid injection experiment, gas is more sensitive to the microchannel size effect than the liquid phase, and hydrophilic liquids flow readily. The gas–water relative permeability value in this study is significantly smaller than that obtained from conventional experiments, based on the steady-state method. This is a result of the gas–water forming a discontinuous plug flow in the microchannel, which produces higher resistance and reduces flow capacity. The occurrence of discontinuous flow regimes challenges the laminar flow assumption adopted in the steady-state method and suggests that conventional laboratory measurements of relative permeability measurements may misrepresent the physics of fluid flows in microchannels. The results also reveal that a hydrophilic environment and a suitable flow rate can increase the two-phase relative permeability. The results of this study enhance our understanding of and approach to core flooding measurement, with the differences in the relative permeability curves indicating that data uncertainty associated with the steady-state method is worthy of further research.

Investigate on mechanism of nanofluid drainage gas recovery in tight gas reservoir

Conventional drainage gas recovery and water-controlled gas recovery technologies are difficult to meet the needs of tight gas reservoirs. In order to solve this problem, nanofluid for drainage gas recovery was proposed to improve the effect of tight gas reservoir development. In this paper, the phase inversion method was used to prepare nanofluid with small particle size. Nanofluid could change the core surface characteristics, improve the drainage effect, and prolong its validity period. The influences of nanofluid on the gas-water flow in tight core and core surface properties have been systematically investigated by the experiments. The mechanism of the drainage gas recovery was discussed. The results showed that nanofluid with different mass concentrations can shift the isotonic point of gas-water relative permeability to the left (58.65%→54.78%@6.25 wt%, 56.49→54.66%@100wt%), reduce the irreducible water saturation (38.35→29.51%@6.25 wt%, 51.75→47.01%@100wt%), greatly increase the water relative permeability (63.79%@6.25 wt%, 100%@100wt%) and slightly reduce gas relative permeability (9.80%@6.25 wt%, 13.04%@100wt%), which has a significant drainage effect. A dense hydrophobic film was formed on the tight core surface to change its microstructure and wettability, which can achieve drainage gas recovery. Nanofluid will have a broad application in tight oil and gas reservoir stimulations.

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Transport Model for Gas and Water in Nanopores of Shale Gas Reservoirs

Because of the many nanoscale pores in shale gas reservoirs (SGRs), the fluid transport mechanisms in shale are complex. Also, previous research has shown that there exists water in the shale plays. Hence, two-phase gas-water transport model construction becomes very important so as to increase accuracy in numerical simulation work. However, most of the current study is still focused on single-phase gas transport. In this paper, based on the second slip model coupled with the fluid single-pipe flow equation, the Knudsen and surface diffusions, and combined with the fractal theory, the relative permeability model for gas-water in shale was constructed. The model reliability was proven by using the available two-phase gas-water relative permeability data. A sensitivity analysis has been carried out based on the proposed model. The results show that with the pressure decreasing, the relative permeability of gas increases. The increase of the pore size distribution fractal dimensions (Df) and fractal dimension (DT) caused the gas relative permeability (Krg) to increase. The Krg increases with the increase of Df and DT. The influence of the viscous slip flow, Knudsen diffusion, and surface diffusion are trade-offs, which are mainly controlled by water saturation (SW) and pressure (P). The Krg is extremely sensitive when P<1 MPa. Under low pressure and low water saturation, the effect of viscous slip flow is secondary. And its contribution increases gradually and becomes the main role with the increase of water saturation or pressure. The effect of the Knudsen diffusion is negligible when P>1 MPa and the water saturation SW>40%. However, it cannot be ignored under other conditions. The influence of surface diffusion reached 21.64%–72.78% when P<1 MPa and SW<10%. A surface diffusion contribution of less than 4.25% was obtained when P>1 MPa and SW>70%.

The Characteristics of Gas-Water Two-Phase Radial Flow in Clay-Silt Sediment and Effects on Hydrate Production

Many hydrate-bearing sediments in the Shenhu area of the South China Sea are featured with unconsolidated clayed silt, small particle size, and high content of clay, which can pose a great challenge for gas production. In order to investigate the gas-water relative permeability in clay-silt sediments, through a radial flow experiment, samples from the target sediment in the Shenhu area were selected and studied. The results show that the irreducible water saturation is high and the influence of the gas-water interaction is obvious. The relative permeability analysis shows that the two-phase flow zone is narrow and maximum gas relative permeability is below 0.1. The flow pattern in clay-silt sediment is more complicated, and the existing empirical models are inadequate for flow characterization. The depressurization method to extract a hydrate reservoir with clay-silt sediments faces the problem of insufficient production capacity. Compared with the ordinary hydrate reservoir with sandstone sediment, the hydrate reservoir with clay-silt sediment has a low permeability and poor gas flow capacity. The gas-water ratio abnormally decreases during the production. It is urgent to enhance production with cost-effective measures.

Simultaneous determination of gas–water relative permeability and capillary pressure from steady-state corefloods

For traditional calculations of relative phase permeability (Kr) from coreflood Steady-State Test (SST), the capillary pressure (Pc) is required. Usually, Pc is determined from a separate test, using a centrifuge or porous-plate methods. However, during SSTs, water cut and pressure drop are measured during the transition period between two sequential fractional-flow steps. We developed a novel method for simultaneous determination of Kr and Pc from SST by using both steady-state and transient data. In the proposed method, the transition data on the pressure drop across the core are used instead of the traditionally utilised Pc-curve. The main idea is that the stabilisation period during each fractional-flow step is inversely proportional to the non-linear saturation-diffusion coefficient in the capillary term of the Rapoport-Leas equation, which in turn is proportional to the derivative of capillary pressure.Interpretation of the pressure-drop transient data depends on their variation during the stabilisation period. The curves for “stabilisation period versus water cut” have a U-shape for water-wet rocks, and the pressure drop variation during the stabilisation period has an S-shape; the corresponding laboratory data approximation regularises the inverse problem. The stability of the algorithm has been checked in wide intervals of the accuracy of measured data. The algorithm was applied to three gas–water laboratory data sets from the literature where X-ray-based saturation profiles have been measured along with the steady-state water cut and pressure drop curves. The close match of the laboratory data validates the method developed.

Hybrid mathematical modelling of three-phase flow in porous media: Application to water-alternating-gas injection

Machine learning algorithms are extensively used to reduce the complexity of applied problems in various fields, including energy. Accurate prediction of the performance of water alternating gas (WAG) injection as an enhanced oil recovery (EOR) process is of great importance in the optimal management of hydrocarbon resources. In the current work, a hybrid mathematical model is proposed for the near-immiscible WAG injection process. We use data-driven sub-models, including least square support vector machine (LSSVM) and adaptive neuro-fuzzy inference system (ANFIS) in series with an empirical model (EM) and a first principle model (FPM) to study three-phase flow in porous media. The LSSVM and ANFIS sub-models predict the two-phase water-oil, gas-oil, and gas-water relative permeabilities. The outputs from these models are supplied to the empirical models (EMs) to estimate the three-phase relative permeabilities for oil, gas, and water phases. The model developed using LSSVM shows a better prediction performance in estimating the relative permeabilities, compared to that using ANFIS. The relative importance parameter analysis reveals that for the LSSVM sub-model, water saturation is the most influencing input parameter for the gas-water and oil-water systems while for the gas-oil system, gas saturation is the most important input parameter. Using the models proposed in this work, some hybrid models are developed to forecast the ultimate recovery factor (RF) in the testing phase. The predicted ultimate RF values are 92.0%, 91.6%, and 82.9% for the correlation-based EM-FPM, LSSVM-EM-FPM, and ANFIS-EM-FPM hybrid models, respectively, in comparison to the measured ultimate RF value of 93.6% after three cycles of water and gasinjection. Among the proposed hybrid models, the LSSVM-EM-FPM model significantly removes the non-linearity of the two-phase relative permeabilities. In general, the LSSVM-EM-FPM hybrid model possesses the same level of accuracy as that of the EM-FPM hybrid model, but with significantly less model complexity and non-linearity. Thus, the LSSVM-EM-FPM hybrid model can be used in demanding applications such as optimization and control of the WAG injection process, leading to a better resource management.

Absolute open flow (AOF) potential evaluation for watered-out gas wells in water-drive gas reservoir

This paper presents a gas-water two-phaseLaminar-Inertial-Turbulent (LIT) flow equation for watered-out gas wells, which can be solved through the incorporation of daily production, gas-water relative permeability and PVT data, and then Q AOF and formation factor (Kh) are obtained. Field case study in Long Wang Miao (LWM) water-drive gas reservoir shows that for watered-out gas wells, the single-phase LIT equation can result in overestimation of Q AOF by 30–80%. Water invasion performance can be relieved after reducing the production rate of watered-out gas wells, and water invasion behavior before breakthrough can be diagnosed with the decline trend of Kh values.

A FRACTAL MULTIPHASE TRANSPORT MODEL IN SHALE POROUS MEDIA WITH MULTIPLE TRANSPORT MECHANISMS AND ROCK–FLUID INTERACTION

Fluid transport in shales is complex due to the various storage spaces and multiple transport mechanisms, especially for multiphase transport during flowback and early stage of production. This study proposes a gas-water relative permeability fractal model during a gas displacing water process in shale gas reservoirs, with incorporations of (1) real gas transport controlled by Knudsen Number (Kn) and second-order slip boundary, (2) slip length for water phase transport, (3) a mobile water film with varying thickness due to rock–fluid interaction and (4) stress-dependence. Specially, the varying thickness of water film is determined according to the extended Derjaguin–Landau–Verwey–Overbeek (DLVO) theory through van der Waals, electrostatic and structural force during a drainage process. Moreover, the organic matter (OM) and inorganic matter (IOM) pore structures are considered with individual pore/tortuosity fractal dimensions. The proposed model is verified by comparing with an analytical model and experimental data. Results show that the decreasing pore pressure during depressurization brings a decline in gas relative permeability, while the decreasing pore pressure has little impact on water relative permeability. The impact of pore and tortuosity fractal dimensions of OM can be ignored compared with that of IOM. Furthermore, neglecting the mobile water film with varying thickness during a gas drainage process leads to an overestimation of gas relative permeability, especially at smaller pore sizes. This work presents a comprehensive model to determine gas-water relative permeability in shales by considering fluids/reservoir properties and rock–fluid interaction in full, which reveals multiphase transport mechanisms in the unconventional reservoirs.

Measurement of Relative Permeability Curves of Cores with Different Permeability and Lengths under Unsteady-State

The oil-water and gas-water relative permeability curves are important reference data for the dynamic analysis and numerical simulation of oil and gas reservoir exploitation. Although the petroleum industry of China and other countries have formulated reference standards for the measuring methods of relative permeability of cores, they haven’t given the definite reference values of the core length, therefore we cannot know for sure whether different core length values are required in the measurement and whether the core length has an impact on the measurement results. In view of this gap, this paper conducted a research on the relative permeability of cores with different lengths. The core samples are artificial core with similar properties as the outcrop cores of the Halfaya Oilfield (Iraq), in our experiment, the oil-water and gas-water relative permeability curves of the sample cores were measured and the results suggest that, for the oil-water relative permeability curves, as the core length grows, the iso-permeability points move to the right, and they basically stabilize when the core length is greater than 20cm; as for gas-water relative permeability curves, in case of low-permeability cores, under constant injection pressure, as the core length grows, the iso-permeability points and the two-phase co-permeation areas present an obvious tendency of moving to the left, but when the core length is greater than 20cm, such tendency is not obvious, and the high-permeability cores do not have such characteristics. These results indicate that, the unsteady-state two-phase relative permeability measurement experiments obtained accurate results at a core length of about 20cm, which provided a reference for similar experiments in subsequent research.

GAS–WATER RELATIVE PERMEABILITIES FRACTAL MODEL IN DUAL-WETTABILITY MULTISCALE SHALE POROUS MEDIA DURING INJECTED WATER SPONTANEOUS IMBIBITION AND FLOW BACK PROCESS

The multiphase flow behavior in shale porous media is known to be affected by multiscale pore size, dual surface wettability, and nanoscale transport mechanisms. However, it has not been fully understood so far. In this study, fractal model of gas–water relative permeabilities (RP) in dual-wettability shale porous media for both injected water spontaneous imbibition and the flow back process are proposed using fractal geometry. The shale pore structure is described as tortuous with different pore sizes and morphologies including slit pore, equilateral triangle, circular pore and square pore. The proportion of each pore morphology can be obtained from SEM/FIB-SEM pore structure characterization results. Injected water spontaneous imbibition after hydraulic fracturing is modeled as the capillary force dominated process and injected water flow back is modeled as a non-wetting gas phase drainage process in inorganic matter. The organic pores are deemed to be not accessible by injected water. The boundary slip of water and free gas flow in the inorganic matrix are considered while both free gas flow and adsorbed gas flow are modeled in organic matter. The proposed gas–water RP fractal model is verified via comparisons with the available experimental data and is discussed in detail. Study results reveal that gas phase RP increases with increasing pore fractal dimensions and tortuosity fractal dimensions, whereas it decreases with increasing Total Organic Carbon (TOC) volumes. Water phase RP decreases with increasing of pore fractal dimensions and tortuosity fractal dimensions, whereas it increases with increasing TOC volumes.

Changes in relative permeability curves for natural gas hydrate decomposition due to particle migration

It is very important to study the fluid flow in a natural gas hydrate (NGH) reservoir for hydrate exploitation. During the decomposition of NGH, some particles fall off and flow with the fluid as a result of poor cementation, which usually leads to sand production in the hydrate mining process. In this study, a three-dimensional pore network model (PNM) was established to simulate the three-phase flow of the gas phase (CH4), water phase, and solid phase (particles). Relevant parameters were set considering the deposition, blockage, and flow in the process of particle migration. Then, the gas–water relative permeability curves under different hydrate saturations, particle diameters, and particle numbers were obtained, considering the influence of the change in the pore-throat space during the hydrate decomposition process. The results showed that the gas–water relative permeability equal points (isotonic points) first turned toward the left and then to the right. The analysis results showed that particle deposition and blockage mainly influenced the relative permeability curves during the early period of the hydrate decomposition process. An increase in the pore-throat space was the main factor affecting the relative permeability curves in the late period of the hydrate decomposition process. Moreover, increasing the particle diameter and number of particles caused the isosmotic points of the relative permeability curves moving to the left as a whole because the pore-throat space decreased. Increasing the number of particles first affected the fluid flow in the hydrate reservoir when the temperature was 280 K, pressure was 5.76 MPa, and hydrate saturation was 0.48. In the actual hydrate mining process, this could cause sudden changes in the relative permeability and production. Thus, this condition needs to be avoided. It has important significance in reference to the process of hydrate mining with sand production.