Gas-water Flow Research Articles

Effective permeability changes during hydrate production

The effective permeability impacted hydrate production severely. But its changes during hydrate production are studied few, due to no stable pressure and temperature for permeability measurement. Herein, this condition was achieved by the intermittent depressurization. The effective permeability of hydrate-bearing samples was measured. The feasibility of this method was analyzed by hydrate dissociation and saturation. Afterwards, the measured and predicted effective permeability were compared and further analyzed from hydrate distribution, preferential flow path, and fresh hydrates. The results showed that hydrate dissociation of 1.24%–2.22% did not impact measurements. Hydrate distribution, preferential flow path, and fresh hydrates were found to have a larger effect on the random changes of the effective permeability during hydrate production in comparison of hydrate saturation and pore habits. The stronger heterogeneity of hydrate distribution caused the greater randomness that the effective permeability difference was 0.346 D-0.4 D at the close hydrate saturations. Under this situation, the fixed preferential flow path was possible to form and stabilized effective permeability at 0.563 D-0.569 D. In the sample with a weaker heterogeneous hydrate distribution, the more apparent randomness was increased by fresh hydrate saturation of 1.66%–5.08%. This work may be beneficial to understand gas-water flow capacity in real settings.

Identification of oil–water-gas flow patterns by super-sparse near-infrared wavelengths sensor

This paper puts forward a method of using two wavelengths of near-infrared light to identify the oil–gas-water mixed flow patterns. Propose a new method of multiple correlation algorithm (MCA) to solve the sensor super-sparse representation problem. Use MCA results as input layer parameters, use BP neural network to train the voltage signal and identify different flow patterns. The experimental results show that the recognition degrees of water, oil bubble, and oil flow patterns have reached 96.77%, 98.39%, and 100%, respectively, and the recognition rate of the water–gas phase has 78.38%. Using a correction model can further improve the accuracy. Test the samples with water cut from 90% to 70%, and the average RMSE = 1.59e-2. This method can be applied to the detection of the water cut of crude oil in oil fields and has a certain reference value for the wavelength selection of near-infrared light sensors.

Gas–Water Flow Behavior during Hydrate Dissociation Using a Developed 2.5D Microfluidic Chip

Gas–Water Flow Behavior during Hydrate Dissociation Using a Developed 2.5D Microfluidic Chip

Experimental Study on the Influence of Wettability Alteration on Gas–Water Two-Phase Flow and Coalbed Methane Production

The surface wettability is important in the change in the relative permeability of gas and water. Due to the heterogeneous property of coal, it has a mixed wetting state, which makes it difficult to predict the change in permeability. To investigate the influence of different wettabilities on two-phase flow, a total of three different rank coal samples were collected and were treated with different chemicals. The alteration of the coal’s wettability, characteristics of gas–water flow, and relative permeability of the coal after the chemical treatments were analyzed. The research conclusions suggest that (1) the coal samples treated with SiO2 and H2O2 increased the hydrophilicity of the coal surface, while the coal samples treated with DTAB increased the hydrophobicity of the coal surface. Compared to SiO2, both H2O2 and DTAB can form a uniform wetting surface. (2) The wettability alteration mechanism among the three different chemical reagents is different. (3) All the chemicals can change the gas–water interface. The water migrates more easily through the cleats after H2O2 treatment, while it is more difficult for the water to migrate through cleats after the DTAB treatment. (4) There are two types of flow states of gas and water on different wetting surfaces. A slug flow is formed on a hydrophilic surface, while an annular flow is formed on a hydrophobic surface. (5) The crossover point and the residual water saturation of the relative permeability curves were influenced by the surface wettability.

Fracturing fluid imbibition impact on gas-water two phase flow in shale fracture-matrix system

A large amount of fracturing fluid in hydraulic fracturing is imbibed into the shale fracture/matrix, which leads to significant uncertainty in gas recovery evaluation. The mechanism of imbibition impact on the gas–water flow is not well understood. In this study, systematic comparative experiments are carried out to simulate imbibition in fractured shale samples obtained from the Wufeng-Longmaxi shale reservoirs in China, and the imbibition effect in the fracture–matrix system is qualitatively and quantitatively investigated. Nine cores are collected to measure their porosity and permeability using a helium porosimeter and nitrogen pulse–decay tests. Gas/liquid single-phase flow experiments are then carried out using methane and KCl solution, respectively. Subsequently, dynamic imbibition experiments are carried out on three samples in a visual cell. The gas–water interfacial tension, water imbibition amount, and displacement velocity are recorded. A single-phase gas/liquid flow test shows a high linear correlation between the fluid displacement velocity and pressure gradient in the fractured samples as the fracture is the main flow channel, dominantly determining the flow behavior. Moreover, the capillary force was introduced in the cross-flow term of the triple-medium model to characterize the imbibition effect, and a two-phase flow simulation model considering the fracturing fluid imbibition retention was developed, and the two-phase flow behavior by considering the imbibition effect of the fracturing fluid retention in the shale gas reservoir was analyzed. Valuable experiment data in this work are provided, which can be used to validate analytical equations for gas/water flow in the shale fracture–matrix system.

Microscopic gas displacement efficiency of enhanced gas recovery in carbonate gas reservoirs with edge and bottom water

Carbonate gas reservoirs with edge and bottom water contain abundant reserves, making them key production targets in the Tarim Basin, Sichuan Basin, Ordos Basin, and other petroleum provinces. Water invasion may occur in the middle and late development stages of such reservoirs, leading to reduction of gas displacement efficiency and gas recovery. In this paper, a pore-scale water-gas immiscible flow model is established by coupling the fluid flow equation and the gas-water contact (GWC) tracking equation. The process of gas displacement with water is simulated in the heterogeneous porous media generated by the quartet structure generation set (QSGS). Finally, the mechanisms of remaining gas distribution and formation are analyzed, and the variation mechanism of microscopic gas displacement efficiency is discussed. The results are obtained in three aspects. First, the remaining gas is distributed at the blind end, in the pore-throat and as clusters, with their proportions and scales jointly controlled by microscopic pore structures, wettability and capillary number. The remaining gas can be further produced by changing the production pressure differential to disturb the original pressure system and gas expansion, so as to improve the microscopic gas displacement efficiency. Second, the microscopic gas displacement efficiency is closely related to the gas flow process. Formation or expansion of each water flow path may cause rapid increase of water cut and slows down the increase of gas displacement efficiency. Third, the microscopic pore structure and wettability are the inherent features of the gas reservoir, so the capillary number can be optimized to change the mode of GWC advancement, and then to effectively improve the microscopic gas displacement efficiency. It is concluded that for real gas wells, the evolution of mechanical mechanisms of GWC advancement should be revealed depending upon the microscopic pore structure and wettability of the reservoir, and then the optimal capillary number can be determined. Furthermore, clarifying the pore-scale water-gas flow characteristics and physical mechanism of microscopic gas displacement provides guidance for the planning of enhanced gas recovery.

Zonal Isolation Material for Low-Temperature Shallow-Depth Application: Evaluation of Early Properties Development

Summary Shallow-depth cementing presents unique challenges due to its low temperature and low pore pressure characteristic. The curing process of the cementitious material is typically prolonged at low temperatures resulting in a delayed curing process. The use of a low-density slurry to mitigate low pore pressure introduces another challenge, as it leads to a reduction in the final compressive strength. On the other hand, the operation requires the material to develop enough strength swiftly to be able to efficiently continue the next drilling operation. In addition, the presence of flow zones such as shallow gas and shallow water flow increases the complexity of the cementing process. There have been many developments in cementitious materials for shallow-depth cementing such as rapid-hardening cement and gas tight cement. However, there is little research focusing on the performance evaluation of each material at low-temperature conditions. This paper aims to present a thorough material evaluation for low-temperature shallow-depth cementing. The incorporated materials are American Petroleum Institute (API) Class G cement, rapid-hardening cement, gas tight cement, and geopolymer. Geopolymer is included to evaluate its potential as the green alternative to Portland-based cement. The sets of characterization were conducted during the liquid, gel, and solid phases. The samples were prepared under wide-ranging low temperatures and typical bottomhole pressures for shallow sections. The result shows different performances of each material and its behavior under low temperatures such as prolonged strength development and low reactivity, which necessitates further development of these materials.

MRI insight on multiphase flow in hydrate-bearing sediment and development mechanism of hydrate seal

Gas and water migration through the hydrate-bearing sediment are characteristic features in marine gas hydrate reservoirs worldwide. However, there are few experimental investigations on the effect of water-gas flow on the gas hydrate reservoir. In this study, gas-water migration in gas hydrate stability zone (GHSZ) was investigated visually employing a high-resolution magnetic resonance imaging (MRI) apparatus, and the formation of hydrate seal was experimentally investigated. Results revealed that normal flow of gas-water at the low flow rate of 1–0.25 mL/min will induce the hydrate reformation. Conversely, higher gas-water flow rates (at 2–0.5 and 4–1 mL/min) need higher reservoir pressure to induce the hydrate reformation. In addition, the hydrate reformation during the gas-water flow process produced the hydrate seal, which can withstand an over 9.0 MPa overpressure. This high overpressure provides the development condition for the underlying gas and/or water reservoir. A composite MRI image of the whole hydrate seal was obtained through the MRI. The pore difference between hydrate zone and coexistence zone produces a capillary sealing effect for hydrate seal. The hydrate saturation of hydrate seal was more than 51.6%, and the water saturation was more than 19.3%. However, the hydrate seal can be broken through when the overpressure exceeded the capillary pressure of the hydrate seal, which induced the sudden drop of reservoir pressure. This study provides a scientific explanation for the existence of high-pressure underlying gas below the hydrate layer and is significant for the safe exploitation of these common typical marine hydrate reservoirs.

Effect of hydrate distribution on effective permeability of hydrate-bearing sediments

Hydrate distribution influences the gas-water flow capacity and thus hydrate production in the hydrate-bearing sediments. The effective permeability is a key parameter to evaluate hydrate production capacity. However, few laboratory studies are focused on the effect of hydrate distribution on the effective permeability in the hydrate-bearing sediments. Thus, the water-phase effective permeability of nine hydrate-bearing samples prepared in a large-scaled pressure vessel under the excess-water setting was measured. The changes of pressure drop, temperature, and the electrical resistance during the measurements were analyzed. The measured and predicted effective permeability were compared. Afterwards, the heterogeneity of hydrate distribution was represented by the net increase of the electrical resistance (NIR) and its variation coefficient (VNIR) to define its effect on the effective permeability. The results showed that water flow channel change for the fresh hydrates caused the averaged pressure drop difference of 39.73 kPa in the repeated measurements. Hydrate dissociation for water flow impacted permeability measurements little. Moreover, the heterogeneous hydrate distribution, instead of hydrate saturation and pore habits, was found to cause a large deviation between the measured and predicted effective permeability. In the sample with hydrate saturation of 3.92%–8.01%, hydrates were mainly distributed at some local position. The corresponding effective permeability had a larger randomness because of the severer heterogeneity. Besides, as hydrate saturation was less than 19.46%, heterogeneity degree changes were opposite to the effective permeability changes. Instead, hydrate distribution impacted the effective permeability little. This work is beneficial to understand the physical properties of the hydrate-bearing sediments.

Pore Structure and Permeability Variations during Gas Displacement in Unconsolidated Sandstone Reservoirs through CT Reconstruction Analysis

The continuous gas displacement in unconsolidated sandstone gas reservoirs will necessarily result in the pore structure and rock permeability variations, which cannot be neglected in the gas development process. However, the variations have not been comprehensively addressed yet, especially for the rock structure in pore scale. This work presented the quantitative results of pore structure in microscale and permeability variations during gas displacement in unconsolidated sandstone reservoirs through computed tomography (CT) reconstruction analysis. The results indicated that a more than 3% increase in porosity after gas displacement resulted from the enlargement of the pore and throat with a diameter of more than 20 μm and 3 μm, respectively, owing to the release and migration of clay and fine particles, in spite of the distribution frequency decline of both pore and throat with a small diameter. The pore connectivity would be enhanced by the increase of the connected pores as well as the enlargement of the pore and throat sizes. However, the pore-throat coordination number could only change with slight improvement. In terms of permeability and relative permeability changes with pore structure, the improvement of permeability after gas displacement was higher than that of porosity, and the continuous gas displacement would broaden gas-water flow region and lower irreducible water saturation and residual gas saturation, and then, the equal phase relative permeability point would shift to the right. These investigations will contribute to more accurate reserve evaluation and productivity prediction.

A water fraction measurement method of gas-water flow in a wide conductivity range

The water fraction of gas-water flow can be measured by a microwave-based approach, but the measurement is unstable if water conductivity is changed. To overcome this, the present study proposes an on-line water fraction measurement method taking advantages of a microwave transmission line sensor. An equivalent circuit and a two-port network are established to reveal that, in a high conductivity environment, the sensor’s S21 phase is linearly related to phase constant and can measure the water fraction. Considering an air-water stratified flow, we conduct experimental and numerical investigations on the variation of the phase against conductivity and water fraction. It is found that 3.31–8.52 S/m conductivity has no effect on the phase. Subsequently, experimental and numerical models are developed for predicting 0–100% water fraction. Both absolute errors are within 2.2% at 95% confidence probability. The simulation method is a low-cost alternative of traditional gas-water flow testing.

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.

Shale gas transport in nanopores with mobile water films and water bridge

Gas flow properties in nanopores are significantly determined by the flow patterns. Slug flow pattern is a potential water–gas two phase flow pattern, in which gas molecules flow in form of gas slugs and water molecules separate gas slugs. Considering water slippage, a portion of water molecules accumulates at the wall with lower mobility, while the remaining water molecules take the shape of a water bridge. Adopting foam apparent viscosity model to represent slug rheological behavior, how water bridge disturbs on gas flow capacity is estimated. The results are compared with the water–gas two phase flow model that assumes annular flow pattern as well as the single gas flow model without the consideration of water. The comparison illustrates that gas molecular movement is significantly hindered by flow space reduction and loss of gas slippage. The impact from water phase of slug flow pattern is more significant than that of annular flow pattern on gas flow capacity. It is discovered that larger nanopores improves gas flow capacity while maintaining bulk water layer thickness and increasing water bridge thickness tend to reduce gas transport ability. A better understanding of the structure and transport of water and gas molecules are conducive to figure out the specific gas–water flow behavior and predict shale gas production.

Tubing Depth Optimization Study of Horizontal Well Drainage and Gas Production in WeiYuan Shale Gas Field

Timely production with a tube in shale gas wells can effectively ensure the stable decline of gas wells. However, there is no in-depth study on which position of tubing is the most favorable for the stable production of gas wells and whether the wellbore trajectory has an impact on this position. To determine the reasonable end of tubing (EOT), firstly, through the gas water flow experiment of the whole wellbore test device of a horizontal well, the characteristics of liquid accumulation in the test section and the liquid discharge at the outlet are analyzed. The results show, when the horizontal section inclines upward and the end of the tubing reaches 1/3 of the horizontal section, the gas flow carrying liquid is the smallest. Then, OLGA software is used to simulate the wellbore effusion in the production process of gas wells with different tubing depths under different wellbore trajectories. The results show when the horizontal section inclines upward and the end of the tubing arrives at 1/3 of the horizontal section, the cumulative production of the gas well is the largest. Based on comprehensive analysis, it is most favorable for horizontal shale gas wells when the end of the tubing is about 1/3 of the horizontal section.

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.

Permeability Model of Unsaturated Fractured Porous Media Based on Tree-like Network and Finite Element Method

In order to characterize the multi-scale structures of fractures and understand the multiphase fluid flow mechanisms in unconventional reservoirs, a physical conceptual model is developed for the gas-water flow through fractured porous media based on tree-like networks. The finite element method is carried out to explore the local flow field properties based on the level set method. The results show that the successive branching ratio and branching angle of the network take significant effect on the absolute permeability and relative permeability of fractured porous media. The proposed model for fractured porous media may provide theoretical basis for the development of unconventional oil and gas resources, carbon dioxide geological sequestration, ground water mining etc.

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.

Modeling evaluation of physiochemical processes controlling gas migration in shallow groundwater systems

Gases may be released into shallow groundwater systems during energy development and geological carbon storage (commonly referred to as gas migration, GM) and can result in greenhouse gas emissions, safety concerns, and the reduction of groundwater quality. The physiochemical processes occurring during GM, including gas release, movement, partitioning, and dissolved-phase transport in the saturated groundwater zone, are difficult to characterize and model; however, modeling is important to develop strategies for detecting and monitoring GM and formulate conceptual models to describe GM at impacted sites. In this study, a previously developed numerical model, which coupled macroscopic invasion percolation (macro-IP) and multicomponent mass transfer, was enhanced to simulate gas releases in the shallow subsurface. Evaluation of the effects of the coupled physiochemical processes was performed by comparing model simulations to previously conducted bench-scale gas injection experiments. Results show that gas flow is highly sensitive to the entry pressures assigned within the model domain and the critical gas saturation (Sg,crit) used to model gas-water flow based on macro-IP; however, mass transfer and the resulting domain-scale dissolved-gas transport were relatively insensitive to these parameters. Multicomponent mass transfer, considering not only the partitioning of the released gas, but also the dissolved background gases ubiquitous in shallow groundwater, was vitally important to simulate dissolution and the resulting free-phase gas distribution within the experimental systems. The use of the local equilibrium assumption for gas-water mass transfer could not consistently describe the experimental observations. Overall, the modeling evaluation performed in this study provides improved understanding of the key processes controlling GM in the shallow subsurface and will advance efforts including up-scaling and scenario testing to accurately quantify the environmental impacts of GM.

Pore-scale investigation on methane hydrate formation and plugging under gas–water flow conditions in a micromodel

Hydrate formation in the pores of porous media is known to decrease reservoir permeability. Current research on hydrate formation in porous media primarily focuses on the static state. In this study, the formation and plugging of methane hydrate under gas–water flow conditions in a visible heterogeneous micromodel were investigated. The experimental results show that the hydrates formed in the pores tended to deposit in situ, and the intersection of different pore channels is critical for hydrate plugging in the micromodel. The higher the pressure in the pore channels, the higher the risk of hydrate formation and plugging. Meanwhile, the hydrate fraction in the pore channels was quantitatively analyzed to describe the hydrate formation and plugging behaviors, which are affected by the hydrate formation and dissolution processes. Based on the experimental results, the formation mechanism of hydrate plugging in microporous channels was proposed, which primarily includes four stages: formation of a water film by the gas–water flow, formation of a hydrate thin shell at the gas–water interface, hydrate deposition in situ and growth, and formation of hydrate plugging. This study establishes the experimental foundation for hydrate plugging prediction models and prevention methods for porous media.

Production Performance Simulation of the Fractured Horizontal Well Considering Reservoir and Wellbore Coupled Flow in Shale Gas Reservoirs

Unmodified original shale gas reservoirs have been demonstrated to have extremely low permeability, and the long horizontal drilling and hydraulic fracturing techniques are widely used to obtain economic gas production. However, these techniques can result in a nonlinear flow of fluids during transport through the multi-scale pore system and the complex fracture network around the horizontal well, as well as a two-phase gas-water flow during shale production. To solve these issues, in this paper, first, the complex fracture network around the horizontal well is characterized using the discrete main hydraulic fractures combined with composite regions with different properties. Then, the dual porosity media and discrete-fracture model are implemented to describe the nonlinear flow behavior in the multi-scale pore system, and a wellbore pressure drop model is established to characterize the transient two-phase gas–liquid flow in the different sections of the fractured horizontal well. Finally, the coupled reservoir wellbore flow model is fully implicitly solved using the control volume finite element method and unstructured tetrahedral grids. The results of the simulation model of a multi-stage fractured horizontal well in the shale of the Longmaxi Formation will help field engineers deeply understand gas and water production performance and the dynamics of wellbore and reservoir pressure, as well as optimize development schemes.