Gas Relative Permeability Research Articles

Impact of pore structure and clay content on the water-gas relative permeability curve within tight sandstones: A case study from the LS block, eastern Ordos Basin, China

The water-gas relative permeability of tight sandstones governs the gas production performance and recovery efficiency in a gas reservoir. Reservoir heterogeneity cannot be neglected when we extrapolate water-gas relative permeability curves. However, efforts to determine the variation with rock types and controls of the gas and water permeability have proven insufficient. Rock composition and pore structures play an important role in the spatial variation of water-gas relative permeability and vary with diagenesis evolution. In this study, we investigated the influence of pore-throat structure, clay content and cements on the water-gas relative permeability curves within tight sandstones using casting thin sections, field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), high pressure mercury injection (HPMI), and gas displacement tests on samples from the LS Block, eastern Ordos Basin, China. The results show that there is a weak relationship between the spatial variation of the water-gas relative curves and the physical properties and pore size distribution of tight sandstones. The length of the two-phase flow zone is not closely related to the porosity and permeability in tight sandstones. The gas relative permeability of the crossing point is closely related to the gas permeability, not the water phase permeability. Nevertheless, the clay content is positive to the gas saturation of the crossing point and the length of the two-phase flow. Subsequently, the water-gas relative permeability curves are divided into three types based on the simultaneous vadose region area (SVRA). Finally, the genesis of the change in the water and gas relative permeability of each type is analyzed.

Wettability alteration and mitigating aqueous phase trapping damage in tight gas sandstone reservoirs using mixed cationic surfactant/nonionic fluoro-surfactant solution

During drilling, completion and fracturing operations, aqueous phase from working fluids can invade into rock formations and engender phase trapping damage in the near well region. This formation damage can diminish the gas relative permeability and hinder the gas well productivity in tight gas sandstone reservoirs. In this study, we investigated the mixed surfactants system of cationic surfactant (SDCSA-1) and nonionic fluorinated surfactant (FC-0) at varied mixing mole ratios and concentrations to reduce the formation damage. Results showed that the minimum surface tension of mixed surfactants solution was relatively low with around 20 mN/m. In addition, surfactant mixtures altered the wettability of sandstone rock from water wetting to intermediate wetting condition. An optimal mixed system was obtained when the concentration is 10-4 mol/L and mole ratio of individual surfactants is 1:1. The mechanism of wettability alteration of surfactants to liquid/rock interface was further determined by adsorption experiments, atomic force microscopy(AFM) tests, and energy dispersive spectrum(EDS) tests. Two sets of spontaneous imbibition experiments were conducted including parallel imbibition tests and sequential imbibition tests. We observed that mixed surfactants solution can prominently prevent liquid invasion into sandstone rocks. We further calculated the capillary pressure to quantitatively examine the capillary effects of different imbibed fluids. When sandstone sample was treated by mixed surfactants, the capillary pressure decreased from 7.81 MPa to 0.97 MPa. Core displacement tests revealed that the liquid saturation of core sample filled with surfactants mixture decreased from 100% to 35.48% and the its gas permeability recovered to 72.86% of the core without liquid after gas flooding. NMR tests also confirmed that surfactant mixtures can be more easily drained than brine from pores in tight sandstone. Consequently, we proposed an improved method to mitigate water blocking damage based on wettability alteration by mixed cationic surfactant and nonionic fluoro-surfactant system.

Nano composites performance as direct thickeners for gas based enhanced oil recovery, a new approach

The thickeners for gas-based enhanced oil recovery must be both gas soluble and capable to significantly enhancing the gas viscosity. However, a large amount of co-solvent is problematic for dissolution of high molecular weight thickeners in hydrocarbon gas. Therefore, in this study the high molecular weight of P-1-D and graphene oxide/P-1-D nanocomposite were synthesized to improve the intermolecular interactions that can increase the gas viscosity at low cloud point pressure without any co-solvent requirement. Results show that the cloud point pressure for nanocomposite gas thickeners is lower than it compared to P-1-D thickener. The high molecular weight of P-1-D and nanocomposites increase the hydrocarbon gas viscosity about 4.5 and 22.9 fold, respectively. In addition, the use of nanocomposites as direct thickener leads to a significant IFT reduction in low concentrations and subsequently increasing the gas relative permeability curve sharply (“X" shape). Moreover, the mobility ratio decreases from 78 to 3.2 for P-1-D and nanocomposite thickeners respectively. However, the capillary numbers increase to 1* 10−3 and the residual oil saturation reduces from 38 to 24 percent.

Effects of Compressive Stress on Carbonation-Induced Degradation of Oil Well Cement under CO<sub>2</sub> Storage Environment

This paper presents an experimental study to investigate the effects of compressive stress during the CO2 attack on wellbore cement under carbon capture and storage (CCS) conditions. Oil well cement samples were designed to be exposed to humid supercritical CO2 gas and CO2-saturated brine and simultaneously subjected to external compressive stresses with load levels of 0, 25%, 50%, and 75% of the ultimate compressive strength. Morphology changes were determined using phenolphthalein dye testing and scanning electron microscopy. Mineral changes were detected by X-ray diffraction. Relative compressive strength and gas permeability of exposed cement were analyzed. It is shown that the 25% stress level has little effect on degradation of cement while the applied compression load up to 50% increased the compactness of cement and finally slowed down the degradation rate. In contrast, a much higher compressive stress level up to 75% facilitated the generation and propagation of micro-cracks. The stress induced micro-crack finally caused a surge in CO2-rich fluids and then significantly accelerated the degradation rate of oil well cement. Findings from this study expanded the understanding of the integrity of oil well cement for CCS wells.

DEVELOPMENT AND CHARACTERIZATION OF SURFACE-MODIFIED NANOPARTICLES USING FLUORINE-BASED CHEMICALS

Scientist have been using chemical treatment to alter the wettability of near wellbore region for condensate banking removal. However, this technique performed unsatisfactorily as the chemical treatment only reduce the surface free energy without modifying the surface roughness and affects the gas relative permeability negatively. Hence, in the present study, an alternative surface-modified nanoparticle using fluorine-based chemicals was developed as a new wettability alteration agent since fluorine exhibits high degree of water and oil repellency. The new wettability alteration agent was evaluated based on FTIR, DLS and TGA characterization. The results show that the surface of nanoparticles has been modified with fluorine-based chemicals coating and this is proven from: FTIR spectra with new peaks observed; DLS characterization with incremental size of surface-modified nanoparticles; and TGA with decomposition rate of coating agents. Implications of the results will path the way for future research direction in using fluorine-surface-modified-nanoparticles as a wettability alteration agent.

Modeling gas relative permeability in shales and tight porous rocks

Accurate modeling of gas relative permeability (krg) has practical applications in oil and gas exploration, production and recovery of unconventional reservoirs. In this study, we apply concepts from the effective-medium approximation (EMA) and universal power-law scaling from percolation theory. Although the EMA has been successfully used to estimate relative permeability in conventional porous media, to the best of our knowledge, its applications to unconventional reservoir rocks have not been addressed yet. The main objective of this study, therefore, is to evaluate the efficiency of EMA, in combination with universal power-law scaling from percolation theory, in estimating krg from pore size distribution and pore connectivity. We presume that gas flow is mainly controlled by two main mechanisms contributing in parallel: (1) hydraulic flow and (2) molecular flow. We then apply the EMA to determine effective conductances and, consequently, krg at higher gas saturations (Sg), and the universal scaling from percolation theory at lower Sg values. Comparisons with two pore-network simulations and six experimental measurements from the literature show that, in the absence of microfractures, the proposed model estimates krg reasonably well in shales and tight porous rocks. More specifically, we found that the crossover point – gas saturation (Sgx) at which transport crosses from percolation theory to the EMA – is non-universal. The value of Sgx is a function of pore space characteristics such as pore size distribution broadness and critical gas saturation. This means that one should expect Sgx to vary from one rock sample to another.

Pore Structure and Permeability Characterization of High‐rank Coal Reservoirs: A Case of the Bide‐Santang Basin, Western Guizhou, South China

AbstractThe methods of nuclear magnetic resonance (NMR) spectroscopy, mercury injection porosimetry (MIP), and gas‐water relative permeability (GWRP) were used to reveal the pore structure and permeability characteristics of high‐rank coal reservoirs in the Bide‐Santang basin, western Guizhou, South China, to provide guidance for coalbed methane (CBM) exploration and exploitation and obtain direct insights for the development of CBM wells. The results indicate that the coal reservoirs in the study area are characterized by well‐developed adsorption pores and poorly developed seepage pores. The bimodal NMR transverse relaxation time (T2) spectra and the mutation in the fractal characteristic of the MIP pore volume indicate poor connectivity between the adsorption pores and the seepage pores. As a result, the effective porosity is relatively low, with an average of 1.70%. The irreducible water saturation of the coal reservoir is relatively high, with an average of 66%, leading to a low gas relative permeability under irreducible water saturation. This is the main reason for the low recovery of high‐rank CBM reservoirs, and effective enhanced CBM recovery technology urgently is needed. As a nondestructive and less time‐consuming technique, the NMR is a promising method to quantitatively characterize the pores and fractures of coals.

Impact of Hydraulic Fracturing on Productivity of Gas Condensate Wells

Having an increase in the discovery of gas reservoirs all over the world, the most common problem related to gas condensate wells while producing below dew point condition is condensate banking. As the bottom hole pressure drops below the dew point, the liquid starts to exist and condensate begins to accumulate. Relative permeability of gas will be reduced as well as the well productivity will start to decline. The effect of applying a hydraulic fracture to gas condensate wells is the main objective of this paper. A compositional simulator is utilized to investigate the physical modifications that could happen to gas and condensate during the production life of an arbitrary well. Performing a good designed hydraulic fracture to a gas condensate well typically enhances the production of such well. This increase depends basically on certain factors such as non-Darcy flow, capillary number and capillary pressure. Non-Darcy flow has a dominant impact on gas and condensate productivity index after performing a hydraulic fracture as the simulator indicates. The enhancement of gas and condensate production can be obtained for gas condensate reservoirs in which the reservoir pressure is above or around the dew point pressure to have a margin for the pressure to decline with time and also eliminate the probability of forming condensate in the reservoir. On the other hand if the reservoir pressure is below the dew point pressure, there will be definitely a condensate in the reservoir and a specific design for the hydraulic fracture is a must to get the required enhancement in the production.

Study on Water Displacing Gas Relative Permeability Curves in Fractured Tight Sandstone Reservoirs Under High Pressure and High Temperature.

Water–gas relative permeability is an important parameter for the rational development of gas fields. Conventional measurement methods are carried out at normal temperature and pressure without considering the actual conditions of high temperature and high pressure. The water displacing gas process in fractured tight sandstone reservoirs, under formation condition (116 MPa and 160 °C), was simulated by the self-manufactured displacing apparatus. The results show that cores under formation condition have the larger residual gas saturation, the smaller two-phase coexisting area, the lower water/gas relative permeability, and the lower displacement efficiency than that under normal conditions. The relative permeability declines slowly and the residual gas saturation is high, making the process of replacing the gas more difficult. The number and the interconnection quality of fractures affect the shape and the position of the displacing curves. It provides a reference for the rational development and further research of fractured tight sandstone reservoir.

Sensitivity analysis of intermittent microwave convective drying based on multiphase porous media models

In this study fundamental models were used by considering heat and mass multiphase transport in a porous medium which was coupled with the intermittent microwave convective combination drying process. The models were validated by experimental data sourced from references, and independent analysis was conducted to select a suitable mesh and time step. Sensitivity analysis was performed using different empirical formula-type input parameters. The water activity and the thermal conductivity mainly influenced on the temperature of the sample, and had no effect on the simulation outputs of moisture content; relative permeability of gas and the capillary diffusivity mainly had an impact on the moisture content of the sample; the specific heat, the binary diffusion coefficient and the dielectric loss factor affected both temperature and moisture content at the same time; the relative permeability of water and the dielectric constant both had no effect on the simulation results. In addition, a sample with a lower thermal conductivity, a higher capillary diffusivity or a higher binary diffusion coefficient tended to form a drier interior as well as a moister surface; a sample with a higher thermal conductivity or a higher specific heat tended to form a more uniform temperature; a sample with a higher capillary diffusivity tended to form a more uniform moisture content.

Investigation on gas permeability of compacted GMZ bentonite with consideration of variations in liquid saturation, dry density and confining pressure

During the long term operation of a disposal repository, gas will be inevitably generated. Determination of gas permeability of compacted bentonite is of great importance for the safety assessment of the engineered barrier system. In the present work, the steady-state and residual pressure methods were employed to determine the gas permeability of GaoMiaoZi (GMZ) bentonite with consideration of variations in liquid saturation, dry density and confining pressure. Results show that, gas migration in saturated GMZ bentonite was mainly controlled by diffusion with an effective gas permeability of 1E-23 m2 - 1E-25 m2. While in unsaturated GMZ bentonite, significant gas flow rates could be observed, which increased stably with the increase of gas injection pressure. Klinkenberg effect was significant when gas flow through GMZ bentonite. The Klinkenberg corrected gas permeability decreased by 3.5–5.5 orders of magnitude as the liquid saturation increased from 10% to 70%. A decreasing magnitude of 1–2 orders in Klinkenberg corrected gas permeability was presented with the dry density increased from 1.5 Mg/m3 and 1.7 Mg/m3. The Klinkenberg corrected gas permeability decreased by 0–1 orders of magnitude as the confining pressure increased from 3 MPa to 7 MPa. By using the accessible porosity, gas measured intrinsic permeability could be determined with values ranged between 1E-15 m2 to 4E-15 m2, which was higher than the water measured one by 5 orders of magnitude. Additionally, a generalized power law was successfully adopted in this study to describe the evolution of gas relative permeability with the liquid saturation. Overall, the effective gas permeability, Klinkenberg corrected gas permeability, intrinsic and relative permeability determined in this study provided a comprehensive perspective to assess the buffering property of GMZ bentonite in multi-physical field coupling environment. The parameters obtained can be adopted in further simulation works for long-term safety analysis of the disposal repository from the viewpoint of gas migration.

Gas and liquid permeability in the variably saturated compacted loess used as an earthen final cover material in landfills

Landfill final covers are crucial to mitigating both the emission of landfill gases and surface water infiltration into solid wastes. Loess that is widely distributed in Northwest China has been transformed into earthen final cover (EFC), although not yet on a large scale. There remains a need for laboratory bench-testing in assessing the performance of this loess as an EFC material, particularly with respect to gas and liquid permeability. To evaluate gas and liquid permeability in the variably saturated loess at the laboratory scale, loess specimens with various resultant dry densities and post-compaction water contents were prepared. Laboratory tests were performed including constant gas pressure-gradient tests and wetting tests in a step-wise fashion to measure gas and liquid permeability as well as water retention behaviours. Large differences were found between intrinsic permeability to gas and liquid, and an empirical power relationship was proposed to characterize the measured intrinsic permeability to gas and liquid relative to the void ratio. The data of relative gas permeability as a function of liquid saturation plotted nearly along a single curve for all dry densities; this was also the case for the relative liquid permeability. Based on the regression results of water retention curves, the measured relative gas permeability values were well described by the van Genuchten–Mulaem (vG-M) model, and a certain difference between the relative liquid permeability evaluated by the vG-M model and the modified Childs and Collis-George equation. An unique relationship was found between the ratio of liquid to gas permeability and liquid saturation for all dry densities, in a range of residual liquid to gas saturation. An empirical model was proposed to efficiently describe gas and liquid permeability of the compacted loess at various liquid saturations and dry densities as well as the data of the loam from another experimental program.

PREDICTED MODEL OF RELATIVE PERMEABILITY CONSIDERING WATER DISTRIBUTION CHARACTERISTICS IN TIGHT SANDSTONE GAS RESERVOIRS

A novel predictive model for calculating relative permeability was derived based on a capillary tube model with fractal theory. Different forms of immovable water including water film (WF) and microcapillary water were incorporated in the new model. Special immovable water called lost dynamic water (LDW) was introduced in the proposed model. The results of verification show that there is agreement between the calculated results and the published experimental data and analytical model. The results indicated that the effect of LDW, WF, and stress dependence had a significant influence on the relative permeability, which cannot be neglected. A larger LDW coefficient, more dead-end pores, and corners in porous media yielded a more complex pore structure. Therefore, more water was trapped in the pore and became connate water, resulting in higher gas relative permeability and lower water relative permeability at a given water saturation. Due to the microcapillary effect, the relative permeability of the water/gas increased/decreased as the drawdown pressure increased at the same water saturation. Higher effective stress was more likely to cause rock deformation, resulting in higher gas relative permeability and lower water relative permeability at a given water saturation. This study provides a significant reference for reservoir engineers conducting water and gas two-phase flow analysis. The theoretical model is beneficial for research into the interpolation of relative permeability via numerical simulation.

Mechanistic Modeling of Water-Alternating-Gas Injection and Foam-Assisted Chemical Flooding for Enhanced Oil Recovery

History-matching of core-flood experimental data through numerical modeling is a powerful tool to get insight into the relevant physical parameters and mechanisms that control fluid flow in enhanced oil recovery processes. We conducted a mechanistic numerical simulation study aiming at modeling previously performed water-alternating-gas and foam-assisted chemical flooding core-flood experiments. For each experiment, a one-dimensional model was built. The obtained computed tomography scan data was used to assign varying porosity, and permeability, values to each grid block. The main goal of this study was to history-match measured phase saturation profiles along the core length, pressure drops, produced phase cuts, and the oil recovery history for each of the experiments conducted. The results show that, to obtain a good match for the water-alternating-gas experiment, gas relative permeability needs to be reduced as a function of injection time due to gas trapping. The surfactant phase behavior, for the aid of foam-assisted chemical flooding, was successfully simulated and its robustness was verified by effectively applying the same phase behavior model to the two different salinity conditions studied. It resulted in the oil mobilization, through the injection of a surfactant slug, being properly modeled. The mechanistic simulation of foam using the steady-state foam model built in UTCHEM proved inadequate for the mechanistic modeling of a foam drive in the presence of oil. An alternative heuristic approach was adopted to overcome this limitation.

Biologically influenced gas fluxes revealed by high‐resolution monitoring of unsaturated soil columns

AbstractModulations of advective gas fluxes at the soil–atmosphere interface were investigated using an enhanced experimental setup developed to perform tracer gas percolation experiments through unsaturated soil columns under well‐controlled conditions associated with long‐term and high‐resolution monitoring. The setup design includes the effect of watering and evaporation cycles, barometric pressure fluctuations, variations in the injection pressure, and plant metabolism. Although injected at a constant flux at the base of the columns, SF6 surface fluxes varied on a timescale of hours to days. These modulations are controlled by (a) barometric pressure, (b) water content and distribution, and (c) plant metabolism. All three mainly act on the pressure gradient. Surface gas fluxes decrease under drying conditions, which increases gas porosity and the relative gas permeability and lowers the pressure gradient. Respiration of plant roots is shown to be responsible for daytime–nighttime oscillations of the tracer flux. During nighttime, O2 consumption and CO2 production locally lowers the pressure gradient up to the root zone due to the higher solubility of CO2 in pore water, resulting in an increased SF6 flux at the surface. During daytime, enhanced water loss by evapotranspiration associated with photosynthesis dominated the respiration effect and resulted in decreasing surface gas fluxes, as generally shown for drying conditions. Surface gas fluxes are therefore controlled by combined physical, chemical, and biological processes. This has important consequences, notably when discrete flux measurements are integrated in space and/or in time to quantify emissions or when used for detecting, identifying, or monitoring underground gas sources.

An Improved Relative Permeability Model for Gas-Water Displacement in Fractal Porous Media

Many researchers have revealed that relative permeability depends on the gas-water-rock interactions and ultimately affects the fluid flow regime. However, the way that relative permeability changes with fractal porous media has been unclear so far. In this paper, an improved gas-water relative permeability model was proposed to investigate the mechanism of gas-water displacement in fractal porous media. First, this model took the complexity of pore structure, geometric correction factor, water film, and the real gas effect into account. Then, this model was compared with two classical models and verified against available experimental data. Finally, the effects of structural parameters (pore-size distribution fractal dimension and tortuosity fractal dimension) on gas-water relative permeability were investigated. It was found that the sticking water film on the surface of fracture has a negative effect on water relative permeability. The increase of geometric correction factor and the ignorance of real gas effect cause a decrease of gas relative permeability.

Simultaneous Interpretation of Three-Phase Relative Permeability and Capillary Pressure for a Tight Carbonate Reservoir From Wireline Formation Testing

AbstractIn this paper, techniques have been developed to interpret three-phase relative permeability and water–oil capillary pressure simultaneously in a tight carbonate reservoir from numerically simulating wireline formation tester (WFT) measurements. A high-resolution cylindrical near-wellbore model is built based on a set of pressures and flow rates collected by dual packer WFT in a tight carbonate reservoir. The grid quality is validated, the effective thickness of the WFT measurements is examined, and the effectiveness of the techniques is confirmed prior to performing history matching for both the measured pressure drawdown and buildup profiles. Water–oil relative permeability, oil–gas relative permeability, and water–oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined using the modified Stone II model. Both the relative permeability and the capillary pressure of a water–oil system interpreted under an oil-wet condition match well with the measured relative permeability and capillary pressure of a similar reservoir rock type collected from the literature, while the relative permeability of an oil–gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the reservoir determined as oil-wet but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water–oil relative permeabilities.

Effective Mechanisms to Relate Initial Rock Permeability to Outcome of Relative Permeability Modification

Excessive water production is becoming common in many gas reservoirs. Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. This manuscript reports the results of an experimental study where we examined the effect of initial rock permeability on the outcome of an RPM treatment for a gas/water system. The results show that in high-permeability rocks, the treatment may have no significant effect on either the water and gas relative permeabilities. In a moderate-permeability case, the treatment was found to reduce water relative permeability significantly but improve gas relative permeability, while in low-permeability rocks, it resulted in greater reduction in gas relative permeability than that of water. This research reveals that, in an RPM treatment, more important than thickness of the adsorbed polymer layer ( e ) is the ratio of this thickness on rock pore radius ( e r ).

Pore-scale investigation of permeability evolution during hydrate formation using a pore network model based on X-ray CT

Abstract Permeability in hydrate-bearing sediment critically governs fluid flow and determines hydrate nucleation, growth, and distribution, making it important to characterize the evolution of permeability with respect to water and gas during hydrate formation. This study uses CT scanning of krypton hydrate formation in silica sand using the excess gas method, together with a pore network model, to investigate variations in hydrate morphology and associated permeation. The results show that during hydrate formation, the growth habit mainly varies from grain-coating to patchy with an increase in hydrate saturation; however, at relatively low saturation, hydrate preferentially grows as a grain-cementing habit. Theoretical models of a capillary tube and of a Kozeny grain both predict that permeability in grain-coating hydrates will be higher than in patchy hydrates. We thus recognise a correlation of permeability and hydrate saturation for multiple growth habits that is of interest for gas production from hydrate reservoirs. Under lower water saturation, there is a decrease in relative permeability to water but an increase in relative permeability to gas, due to the reduction in pore shape factors. Conversely, an upward shift in relative permeability to water and a downward shift in relative permeability to gas is found with hydrate formation under higher water saturation, owing to the Jamin effect. Steeper curves of relative permeability to gas and water with increasing hydrate saturation resulted in a reduction of the co-cementation zone for water and gas, even if or though no gas migrates. The results suggest that, due to the low relative permeability of gas, higher water saturation sediments result in an excess water yield accompanied by low gas production that is not desirable for natural gas hydrate production. Therefore, improving the permeability and weakening the Jamin effect are critical for gas production in marine hydrate reservoirs, especially in low permeability sediments.

Complete gas-brine imbibition relative permeability curves increase confidence in gas field performance

The standard methods used for measuring gas relative permeability during brine imbibition have been found to be inadequate as the resulting curves are incomplete and may include invalid points. CSI...