Gas-water Relative Permeability Research Articles

Permeability anisotropy analysis of two-phase flow during hydrate dissociation process

Natural gas hydrate (NGH) is a versatile and energy source. But in the actual extraction process, NGH in the reservoir will be out of phase equilibrium conditions and dissociate. This will induce alterations in permeability characteristics of reservoir and will exert a significant influence on the assessment of hydrate reservoir capacity. In the research, an innovative CT triaxial system was used to obtain the micro-structure of sediment specimen during hydrate dissociation. The anisotropy of absolute permeability (k), capillary pressure (Pc) and relative permeability (kr) were also analyzed using the pore network model (PNM). As demonstrated by the results, k increases gradually in all three directions during the dissociation. Pc gradually decreases. The degree of anisotropy of both Pc and gas-water relative permeability (krg and krw) gradually decreases. The impact of hydrate dissociation on the kr anisotropy during primary gas flooding surpasses that observed during secondary water flooding. As hydrate saturation decreases, the krw increases and the krg decreases in the horizontal directions. The krw does not change significantly and the krg increases in the vertical direction. Along the length of the sample, the distribution of hydrate and pore space exhibits heterogeneity across the sections. This inhomogeneous distribution will lead to anisotropy in permeability.

Effect of pore structure characteristics on gas-water seepage behaviour in deep carbonate gas reservoirs

The study of gas-water two-phase flow behavior has always been a focus and a difficult problem in the field of oil and gas seepage, and it is related to the formulation of reasonable development plans for oil and gas reservoirs. Deep carbonate gas reservoirs (depth>4500m) develop cross-scale porous media, which have extremely strong heterogeneity and very complex seepage characteristics. To the best of our knowledge, there has been no systematic study on the two-phase flow patterns of gas and water in deep carbonate gas reservoirs. This paper uses cast thin sections, scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) to study the influence of carbonate rock pore structure characteristics on gas storage and seepage capabilities. The results show that the existence of cavities enhances the gas storage capacity of the reservoir and improves the seepage capacity of pore-throat space near the cavity. Fractures can effectively communicate with isolated cavities, enhance reservoir connectivity, and thereby significantly improve the overall seepage capacity of the reservoir. The centrifugal technique was combined with NMR to study the movable fluid characteristics of carbonate reservoirs. The critical flow throat radius and movable fluid saturation of the reservoir reveal that the degree of development of cavities and fractures determines the mobility of the fluid in the reservoir. The fluid mobility in the fracture-cavity-type reservoir is the strongest, while the fluid mobility in the pore-type reservoir is the weakest. Analysis of the normalized curve of gas-water relative permeability under high temperature and pressure reveals that formation water preferentially enters connected pores with low seepage resistance, and the strong storage capacity of cavities can effectively delay the non-uniform intrusion of formation water. The results of water invasion simulation experiments show that the water invasion phenomenon can improve the gas production rate and recovery rate of pore-type reservoirs. However, the formation water flow and channeling phenomena caused by reservoir heterogeneity will cause a large amount of gas to be sealed in the pore space of cavity-type and fracture-cavity-type reservoirs, reducing the recovery rate and economic benefits of these reservoirs. These findings further provide solid fundamentals for efficient and effective exploitation of deep carbonate gas reservoirs.

Gas–water percolation of tight sandstone reservoirs with different pore types in the Ordos Basin

AbstractTo investigate the percolation mechanism of tight sandstone reservoirs, qualitative and quantitative methods are applied to analyze the pore structure of the Ordos Basin through scanning electron microscopy and high-pressure mercury injection. Based on gas–water relative permeability data and the visualization of real sandstone models, a gas–water displacement experiment was carried out to simulate the percolation mechanism and fluid distribution of different pore types. The results show that: ① The percolation of different pore types varies greatly, and the irreducible water saturation decreases when the reservoir properties improve. The relative permeability of gas at an irreducible water saturation increases, the width of the two-phase percolation area increases, and the percolation ability is enhanced as the reservoir properties improve. ② The gas–water displacement mode changes from fingering to uniform displacement with the improvement of pore type, which is beneficial to the formation of effective reservoirs filled with natural gas under the same hydrocarbon generation conditions. ③ The time required for the pressure relief of samples with good reservoir properties is short, and the recovery is higher with the improvement of pore type. ④ The residual water in samples with a poor pore type increases, which decreases the relative permeability of gas and recovery. A reasonable development pattern should be carried out, and the production pressure difference should be strictly controlled to maximize productivity. This study provides theoretical guidance for the development of tight sandstone reservoirs in the Ordos Basin.

Estimating the Influencing Factors of Gas–Water Relative Permeability in Condensate Gas Reservoirs under High-Temperature and High-Pressure Conditions

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs.

A New Method for Numerical Simulation of Coalbed Methane Pilot Horizontal Wells—Taking the Bowen Basin C Pilot Area in Australia as an Example

Coalbed methane (CBM) pilot wells typically exhibit a short production period, necessitating evaluation of their estimated ultimate recovery (EUR) through numerical simulation. Utilizing limited geological data from the pilot areas to finish history matching and subsequent production forecasting presents substantial challenges. This paper introduces a comprehensive numerical simulation workflow for CBM pilot wells, encompassing the following steps. Initially, geological parameters are categorized into two groups based on their statistical distribution trends: trend parameters (i.e., gas content, permeability, Langmuir volume, and Langmuir pressure) and non-trend parameters (i.e., fracture porosity, gas–water relative permeability, and rock compressibility). The probability method is employed to ascertain the probable high and low limits for trend parameter distributions, while empirical or analogous methods are applied to define the boundaries for non-trend parameters. Subsequently, the parameter sensitivity analysis is conducted to understand the influence of varying parameters on cumulative gas and water production. Conclusively, experimental design algorithms generate over 100 simulation cases using the identified sensitive parameters, from which the top ten optimal cases are chosen for EUR prediction. This workflow features two technological innovations: (1) considering the most comprehensive set of reservoir parameters for uncertainty and sensitivity analyses, and (2) considering the matching accuracy of both cumulative production and dynamic production trends when selecting optimal matching cases. This approach was successfully implemented in the C pilot area of the Bowen Basin, Australia. In addition, it offers valuable insights for numerical simulation of unconventional natural gases, such as shale gas.

Anisotropy analysis of two-phase flow permeability in the multi-stage shear process of hydrate-bearing sediments

Natural gas hydrate is a promising energy resource for the future. However, due to the shallow burial and low-degree of consolidation, hydrate-bearing sediment (HBS) is prone to deform under stress. And this will lead to dynamic changes in reservoir permeability. In this study, the micro-structure of shearing HBS specimen with hydrate saturation of 45.1% under different confining pressures (1, 3 MPa) were obtained by the micro-focus CT, the micro-structure changes and two-phases permeability characteristics evolution were analyzed. The results show that with the increasing axial strain, the absolute permeability increase firstly and decrease. The capillary pressure in vertical direction is always larger than that in horizontal directions. During primary gas flooding and secondary water flooding, the gas-water relative permeability anisotropy of different direction gradually enhances, and reach maximum with the largest axial strain. At low effective confining pressure, the gas-water relative permeability in each direction does not vary with axial strain. At high effective confining pressure, the relative water permeability in each direction decreases with the increase of axial strain, the relative gas permeability in the horizontal direction increases with the increase of axial strain, and the relative gas permeability in the vertical direction has no obvious pattern.

Prediction Model for Tight Gas Wells with Time-Dependent Mechanism and Stress Sensitivity Effect.

In the production process of tight gas wells, reservoir fluid distribution and gas-water relative permeability vary with time. However, traditional models fail to handle the time-dependent mechanism and stress sensitivity effect in the reservoir, leading to significant errors in the dynamic analysis results. To address this issue, this article presents a prediction model for fractured well production in tight gas reservoirs. It is based on a three-dimensional embedded discrete fracture model (EDFM), which considers the influences of the time-dependent mechanism and stress-dependent reservoir permeability. Transient flow equations are treated by using the finite volume method to obtain the solution of the model. The accuracy and reliability of the model are verified by comparison with the results of the commercial simulator Eclipse and the field application. Based on the model's solution, this study emphasizes the analysis of the impact of the time-dependent mechanism and reservoir stress sensitivity on gas well productivity. Simulation results show that the time-dependent relative permeability curve can decrease the level of irreducible water saturation and promote the migration of irreducible water, resulting in an increase in water permeability and a decrease in gas permeability. This effect will reduce the period of stable gas production and increase the level of water production. Besides, reservoir stress sensitivity will reduce daily water production and accelerate gas well decline. It is necessary to control the production pressure difference reasonably during the production process to effectively reduce the negative impact of stress sensitivity effects. The results indicate that when the relative permeability curve and the reservoir permeability are constant, the real gas production capacity of the reservoir will be strengthened. The application of field case studies shows that the theoretical model exhibits stronger adaptability, achieves better fitting results, and can guide the compilation and adjustment of development plans for water-bearing tight gas reservoirs. These findings provide insights into understanding the effects of the time-dependent mechanism on gas production rates in tight gas reservoirs. Furthermore, this study offers useful guidance for the prediction of field-scale gas production.

The differences on gas–water relative permeability characteristics of low and high rank coal and its controlling factors

A comprehensive comparison was conducted in terms of the gas–water relative permeability characteristics of high rank coals from south Qinshui Basin and low rank coals from Erlian Basin, China. The results show that: High rank coal samples are featured with a larger percentage of micropores. Compared with high rank coal samples, low rank ones display a smaller irreducible water saturation (S wo) and higher methane (K rg) and water (K rw) permeability and wider spans of two-phase flow region. High rank coal samples with a large percent of micropores are featured with a larger S wo and a narrower two-phase flow span. Gas displacement pressure increases K rg, while decreases K rw and S wo, and the changing rule is more pronounced in low rank coal samples. The effective stress is inversely proportional to the K rg and the span of two-phase flow, whereas proportional to the K rw. Influenced by effective stress, the dynamic changes of the cross points are more obvious in the low rank coal samples, however that of two-phase flow spans and S wo are not so pronounced. The conclusion will be helpful for CBM exploration and development.

An improved digital-rock random construction method and flow simulation considering pore and fracture coupling of shale gas reservoirs

Random construction of digital rocks based on scanning electron microscope (SEM) images is an effective method to investigate shale gas flow. Limited researches have been conducted to take into account the practical shape of organic matter or the coupling of fractures and pores during the reconstruction of digital rock samples, which would lead to the flow simulation results deviating from the real situations. In this work, the traditional segmentation method of SEM image using threshold algorithm was modified to calculate the morphological parameters of multi-components shale structures. Then, the classical four-parameter random growth algorithm was improved to construct the shale digital rock. Finally, we conducted flow simulation on the digital rocks through pore network model (PNM). Some complex structures (e.g., rough fracture and pyrite framboid) in shale can still be properly generated by controlling the growth parameters in the algorithm. Compared to the previous reconstruction methods, we incorporated the diagenetic sequence of shale components and more realistically described the morphology of organic matter and inorganic matter. After considering the complex structures, the structure characterization parameters such as pore size distribution and porosity distribution among 2D slices are consistent with the real sample, thus improved the representativeness of reconstructed rock samples. The coupling of fracture significantly improved the connectivity of PNM, resulting in an increase in absolute permeability from 3.492 × 10−9μm2 to 7.019 × 10−5μm2 and lower left movement of the capillary pressure curve. For the gas-water relative permeability curve, the addition of fracture extends the two-phase flow region, and decreases the bound water saturation from 0.63 to 0.19 during the drainage process, which facilitates the flow of the gas-water two phases. This work highlights the importance of considering organic matter morphology and fractures in shale digital rock, which provide fundamental insights into reservoir characterization and simulation.

Experimental determination of gas-water relative permeability for ultra-low-permeability reservoirs using crushed-rock samples: Implications for drill cuttings characterization

Relative permeability controls fluid flow through rocks, with applications to hydrocarbon production, geologic carbon and energy storage. However, significant challenges are associated with the measurement of relative permeability for rocks with matrix permeability in the microdarcy to nanodarcy range. The primary objectives of this study are therefore to 1) propose an integrated experimental and modeling approach for gas relative permeability (krg) evaluation using crushed-rock samples and 2) perform a proof-of-concept study to demonstrate that gas–liquid relative permeability can be determined for ultra-low-permeability (unconventional) reservoir samples that have been crushed to certain grain sizes (20–35 mesh size).In this study, the water vapor ad-/desorption technique was employed to provide a wide range of water saturations (Sw). The evolution of water distribution in the shale matrix with a change in Sw was investigated by using a modified low-pressure adsorption (LPA) technique. A recently-developed numerical model was modified to estimate effective permeability to gas at each saturation level. Four clay-rich shales from the Duvernay (Canadian) and Kyalla (Australian) formations were analyzed.The vapor ad-/desorption technique provided an efficient approach to saturate the studied samples. By changing relative humidity in sealed desiccators using different salt solutions, a maximum Sw of 83% was obtained for organic-matter rich samples, and 99% for organic-matter lean shales. As interpreted using the modified LPA technique applied at different saturation levels, water is held in films in mineral-associated macro-/mesopores, and can block access to organic-matter pores through the formation of water clusters, significantly reducing the accessible organic-matter porosity and gas effective permeability. Imbibition krg decreases rapidly and significantly (over 90%) when Sw reaches approximately 0.3–0.4 for samples containing significant amounts of water-sensitive clay minerals (Kyalla #2) and TOC (Duvernay #2). Relative permeability hysteresis occurs for Duvernay #2 and Kyalla #1. Overall, the use of crushed-rock samples (non-matrix/fracture system), and application of the vapor sorption technique, results in a small amount of hysteresis.A laboratory-based method for measuring gas relative permeability of ultra-low-permeability reservoirs using crushed-rock samples is provided for the first time, with important applications to the energy and carbon capture industries.

Pore-scale modeling of pore structure properties and wettability effect on permeability of low-rank coal

Permeability is a key parameter for coalbed methane development. Although the absolute permeability of coal has been extensively studied, wettability and pore structure properties continue to challenge the microscopic description of water-gas flow in coal. For this purpose, we reconstructed the microstructures of low-rank coal using micro-computed tomography (micro-CT) images. Pore geometry and pore-throat parameters are introduced to establish a relationship with absolute permeability. A dual-porosity pore network model is developed to study water-gas displacement under different wetting and pore structure properties. Results show that absolute permeability is significantly affected by pore geometry and can be described using a binary quadratic function of porosity and fractal dimension. Water-gas relative permeability varies significantly and the residual gas saturation is lower; the crossover saturation first decreased and then increased with increasing porosity under hydrophobic conditions. While the water relative permeability is lower and a certain amount of gas is trapped in complex pore-throat networks; the crossover saturation is higher under hydrophilic conditions. Models with large percolating porosity and well-developed pore networks have high displacement efficiency due to low capillary resistance and avoidance of trapping. This work provides a systematic description of absolute permeability and water-gas relative permeability in coal microstructure for enhanced gas recovery.

Prediction of gas–water relative permeability in tight rock from movable fluid distribution with nuclear magnetic resonance

The measurement of the relative permeability in tight rock is challenging due to its ultralow permeability and the time-consuming nature of the experiments. Studying the movable and unmovable fluid distribution and establishing a reliable relative permeability prediction model is an urgent problem to be solved. This paper used nuclear magnetic resonance (NMR) to investigate movable and unmovable water distribution in tight sandstone under different centrifugal forces. A new method for predicting gas–water relative permeability in tight rock is established based on movable fluid distribution using the capillary bundle model. The results show that the distribution of movable and unmovable fluids is strongly influenced by the tight rock's pore size distribution and structure. The unmovable fluid saturation increases as the tight rock's permeability and median radius decrease. The nonlinear correlation between the NMR relaxation time and the pore throat size obtained from high-pressure mercury intrusion can be used to derive the pore size of the fluid distribution in tight rocks. The ratio of the movable fluid thickness to pore throat size increases near linearly with the logarithm of the pore throat size. The proposed mathematical model for the prediction of gas-water relative permeability based on movable fluid distribution is verified by comparing with the normalized relative permeability curve measured from experiments. This new model offers an alternative method of estimating the gas–water relative permeability when measurement is unavailable due to the ultralow permeability of the core samples.

Experiment on the Gas Permeability and Gas–Water Relative Permeability in High-Rank Coal with a Self-Developed Device

Water saturation, displacement pressure, and gas type are essential factors affecting the seepage characteristic of fluid in coal due to the swelling induced by gas adsorption. However, the understanding of the seepage behavior of water, CH4, and CO2 in coal seams is still poor owing to the lack of research. In this work, a series of gas permeability and gas–water relative permeability experiments were conducted by our self-developed device. The results can be summarized as follows: (1) with the increase in water saturation, the gas permeability decreased rapidly at first and then reduced sharply again after a period of slow decline; (2) the two-phase flow span showed no significant difference for He–water and CH4–water systems under different displacement pressures, but it increased for CO2-water system. The different behaviors of the two-phase flow span suggested that the effect of displacement pressure on relative permeability properties is dependent on the gas type. (3) The CO2–water relative permeability showed a sizeable two-phase flow span compared to the He–water or CH4–water system under the same displacement pressure, and the gas relative permeability decreased obviously in the following sequence: He > CH4 > CO2. The concept of relative permeability surface was proposed based on the experimental results. A parametric interpolation method was applied to determine the relative permeability surface, which could be used to accurately describe the flow characteristics of fluids in a mixed gas–water system.

A Novel Semianalytical Model for the Relationship between Formation Pressure and Water Saturation in Coalbed Methane Reservoirs

The accuracy of the relationship between formation pressure and water saturation has a direct impact on predicting the production performance of coal reservoirs. As a result, researchers are becoming more interested in this connection. The most commonly used method to evaluate this connection is the semianalytic method, but it disregards the impact of coal matrix shrinkage on pore compressibility, resulting in inaccurate water saturation estimations for coal reservoirs. A material balance equation that considers the effect of coal matrix shrinkage on cleat porosity and pore compressibility, as well as the gas–water relative permeability curve, is used for the first time in this study to establish a model between pressure and water saturation. Furthermore, this study extends the proposed pressure–saturation model to predict cumulative gas production and gas recovery, resolving the difficult problem of calculating recovery for coalbed methane reservoirs. To verify its accuracy, this study compares the proposed method with numerical simulations and previous methods; the results of the comparison show that the water saturation under formation pressure calculated by the method proposed in this study is closer to the results of the numerical simulation. Sun’s model ignores the effect of matrix shrinkage on pore compressibility, resulting in larger calculation results. The findings of this study indicate that the effect of coal matrix shrinkage on pore compressibility cannot be ignored, and that the proposed method can replace numerical simulation as a simple and accurate method for water saturation evaluation, which can be applied to predict cumulative gas and recovery estimation for closed coalbed methane reservoirs. The proposed method increases the accuracy of the semianalytical method and broadens its application. It is critical for the prediction of coal reservoir production performance and forecasting of production dynamics.

MULTIFRACTAL MODELING OF GAS–WATER RELATIVE PERMEABILITY CONSIDERING MULTISCALE AND MULTIEFFECTS: INVESTIGATION OF UNCONVENTIONAL GAS DEVELOPMENT

Unconventional gas is a momentous energy source due to its considerable reserves and eco-friendly properties, where relative permeability is a key evaluative parameter of unconventional gas extraction. However, the geo-complexity, multiscale and multieffect of the unconventional gas reservoir challenge the relative permeability evaluation and production enhancement. Here, we establish a gas–water flow model by integrating multifractal theory, covering from nanoscale to macroscale and regarding the effects of slip, gas desorption–diffusion and water film separation, to reliably evaluate the relative permeability evolution during unconventional gas development. Based on our model, we describe the permeability of the unconventional reservoir with an 88% less evaluation error compared to the single fractal Darcy with the literature benchmark. Moreover, we characterize the gas–water relative permeability with a no more than 10% evaluation error based on the experimental data. The slip effect plays the most crucial role in the evaluation precision of relative permeability. We reveal that the permeability of the unconventional gas reservoir is decreased by the increase of generalized fractal dimension which enhances the heterogeneity and tortuosity of pores. We uncover that the slip effect facilitates the relative permeability of gas and water. Besides, the gas desorption–diffusion boosts gas relative permeability while limiting water relative permeability, whereas water film separation enhances water relative permeability but hinders gas relative permeability. This work brings insights into the precise description of multiscale and multieffect gas–water porous flow in unconventional gas development.

An improved experimental procedure and mathematical model for determining gas-water relative permeability in tight sandstone gas reservoirs

The gas-water relative permeabilities (GWRPs) of five rock samples were determined under different pore pressures to analyze and model the effects of pore pressure and rock-sample permeability in tight sandstone gas reservoirs. The gas-water permeability curves measured at 10–30 MPa are higher than those at normal pressure, and the co-permeability interval is narrower. At the same water saturation, the relative permeabilities of gas and water decrease with increasing pore pressure, especially that of gas. Under the same pore pressure conditions, with decreasing absolute permeability, gas-water relative permeability decreases, with the difference becoming smaller with increasing pore pressure. Finally, the experimental data for four rock samples was subjected to multiple linear fitting using Origin software, and a mathematical model of gas-water relative permeability was established. The accuracy and applicability of the mathematical model were verified by comparing the gas-water permeability curve calculated by the mathematical model with the experimental results for the fifth rock sample. Our findings provide invaluable information regarding gas-water two-phase seepage during the development of tight sandstone gas reservoirs and make predicting their productivities and production performances more accurate.

Experiments on Water-Gas Flow Characteristics under Reservoir Condition in a Sandstone Gas Reservoir

For gas reservoirs that contain water, investigating characteristics of water–gas seepage is crucial to the formulation of gas field development plans and predicting the production capacity and water breakthrough of gas wells. For the purposes of such an investigation, the process of water invasion into a water-containing gas reservoir was studied based on four sandstone samples whose physical properties differed quite vastly (permeability: 0.112–192.251 mD; porosity: 8.33–20.60%). Gas–water relative permeability experiments were conducted on the gas-driven water in the reservoir conditions (temperature: 135 °C; pressure: 75 MPa). Starting with the sandstone samples’ microstructural characteristics, particular attention was paid to the impacts of throat radius and clay content on the water–gas seepage characteristics. It was found that the basic physical properties, microscopic characteristics, and mineral composition of the sandstone samples all affected the water–gas seepage characteristics. The larger the pore-throat radius, the stronger the ability of sandstone samples to allow fluid through under the same water saturation and the greater the relative permeability of gas and water phases. Furthermore, the wider the throat radius and the lower the clay content, the greater the gas–water relative permeability. Isotonic water saturation and irreducible water saturation were found to be negatively to throat radius and positively with clay content. Furthermore, When sandstone samples have similar clay content, the average throat radius is four times larger, its irreducible water saturation is decreased by 1.63%, its residual gas saturation is decreased by 1.00%, and the gas permeability under irreducible water saturation increases by more than 400 times. Water intrusion showed a more significant impact on the gas–water flow characteristics of the low-permeability sandstone samples, and it severely restricted the flow capacity of the gas phase.

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.