Stress dependent gas-water relative permeability in gas hydrates: A theoretical model

Lei, Gang; Liao, Qinzhuo; Lin, Qiyuan; Zhang, Liangliang; Liu, Xue; Chen, Weiqing

doi:10.46690/ager.2020.03.10

Cited by 30 publications

(15 citation statements)

References 52 publications

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“…The Shenhu sediments are a poorly cemented porous media, thus it is difficult to obtain permeability using conventional methods (Lei et al., 2020). This is especially true as hydrate grows in the sediments under high pressure and low temperature conditions with water or gas flowing through the sample.…”

Section: Resultsmentioning

confidence: 99%

Gas hydrate in-situ formation and dissociation in clayey-silt sediments: An investigation by low-field NMR

Sun

Qin

et al. 2020

Energy Exploration & Exploitation

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The hydrate reservoir in the Shenhu Area of the South China Sea is a typical clayey-silt porous media with high clay mineral content and poor cementation, in which gas hydrate formation and dissociation characteristics are unclear. In this study, the CO2 hydrate saturation, growth rate, and permeability were studied in sandstone, artificial samples, and clayey-silt sediments using a custom-built measurement apparatus based on the low-field NMR technique. Results show that the T2 spectra amplitudes decrease with the hydrate formation and increase with the dissociation process. For the artificial samples and Shenhu sediments, the CO2 hydrate occupies larger pores first and the homogeneity of the sandstone pores becomes poor. Meanwhile, compared with the clayey-silt sediments, CO2 hydrate is easier to form and with higher hydrate saturation for the sandstone and artificial samples. In hydrate dissociation process, there exists a protection mechanism, i.e. the dissociation near the center of hydrates grain is suppressed when gas pressure drops suddenly and quickly. For permeability of those samples, it decreased with hydrate forms, and increases with hydrate dissociation. Meanwhile, with the same hydrate saturation, permeability is higher in hydrate formation than in dissociation.

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Section: Resultsmentioning

confidence: 99%

Gas hydrate in-situ formation and dissociation in clayey-silt sediments: An investigation by low-field NMR

Sun

Qin

et al. 2020

Energy Exploration & Exploitation

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“…However, the chemical analysis of the natural gas composition from the core indicates the presence of heavier gas compounds with high dryness coefficients, which gradually decrease with depth to an average value as low as 0.88. 39 Considering what was obtained by the simulation, a wet gas with a dryness coefficient of 0.88 can form a 735 m thick HSZ at a depth interval of 115–850 m under similar formation temperature and frozen soil conditions. Likewise, a gas with a lower dryness coefficient is favorable for hydrate formation, such as an associated gas and condensate.…”

Section: Discussionmentioning

confidence: 62%

“…An exploratory well, MK-2, was drilled near Beiji village in the north of the Mohe Basin, and an abnormally high amount of adsorbed gas was recovered from the cores at the depth interval of 800–1700 m via a desorption process. 39 , 51 Such a phenomenon invalidates the findings of this study about the occurrence of pure methane HSZs. However, the chemical analysis of the natural gas composition from the core indicates the presence of heavier gas compounds with high dryness coefficients, which gradually decrease with depth to an average value as low as 0.88.…”

Section: Discussionmentioning

confidence: 69%

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Theoretical Prediction of the Occurrence of Gas Hydrate Stability Zones: A Case Study of the Mohe Basin, Northeast China

et al. 2021

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Source rocks of the Mohe Basin, Northeast China are gas-prone and the organic matter has advanced to late oil-generation stages, producing condensate and natural gas. This provides suitable conditions for the Mohe Basin to become one of the most prolific terrestrial natural gas hydrate (NGH)-bearing areas in China. Knowing this, here we predict the depth and thickness of pure methane hydrate stability zones (HSZs) and gas hydrate stability zones (GHSZs) via simulating the hydrate-phase equilibrium and other formation P – T conditions. Furthermore, factors that have a major impact on the occurrence of HSZs are discussed. Results showed that the composition of gas (guest) molecules and the geothermal gradient are the two most controlling factors on HSZs. Moreover, it was found that a pure methane HSZ with a thickness of about 255 m can form in areas with a geothermal gradient of <1.5 °C/100 m, with top and bottom depth limits less than 493 m and greater than 748 m, respectively. In contrast, pure methane hydrates have difficulty forming, while hydrates from wet gas can form where there is a geothermal gradient of >1.6 °C/100 m. Furthermore, a wet gas HSZ with a thickness of at least 735 m can be expected when the geothermal gradient reaches 2.3 °C/100 m, with top and bottom depth limits at 115 and 850 m, respectively. Ultimately, a pure methane HSZ can still form in the abnormally high-pressured areas when the geothermal gradient is up to 2.0 °C/100 m. Overall, HSZs can occur due to the combined effect of formation temperature, pressure, and gas composition. Finally, based on the results from this study and drilling data, future successful hydrate drilling schemes can be implemented in the Mohe Basin and similar terrestrial areas.

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“…If an oil reservoir rock is relatively stress sensitive, it is necessary to take immediate actions to avoid porosity and permeability reduction. The production potential of gas hydrates mainly depends on permeability characteristics of the bearing sediments as high permeability could promote the production rate [1]. And the enhancement of gas effective permeability with increased gas saturation weakens with higher complexity and lower discreteness of a pore network.…”

Section: Introductionmentioning

confidence: 99%

Determining Triaxial Stress Sensitivity of Oil Reservoir Rocks without Fluid Flooding

Hu²

2021

Geofluids

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The sensitivity of oil reservoir rocks to stress is the basis for oilfield development, which determines the production method employed in the field. Therefore, it is critical to understand the stress sensitivity behavior of oil reservoir rocks in an oilfield. In this paper, a novel method for determining the stress sensitivity of oil reservoir rocks by triaxial stress testing without fluid flooding was proposed. It measures the triaxial stress and strain of the core rock samples, and based on which, the core porosity and permeability under stress can be evaluated by theoretical model. In the model, the pores of the core were assumed to be a bundle of capillaries and the necessary relationship was derived to calculate the changes of porosity and permeability of the core samples caused by the strain. Through comparison with and analysis of experimental results obtained for various rock core samples under different stress and strain conditions, it is observed that the theoretical model match well with that of the experiments. This method provides a new approach for the stress sensitivity analysis of oil reservoirs without fluid flooding.

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Stress dependent gas-water relative permeability in gas hydrates: A theoretical model

Cited by 30 publications

References 52 publications

Gas hydrate in-situ formation and dissociation in clayey-silt sediments: An investigation by low-field NMR

Gas hydrate in-situ formation and dissociation in clayey-silt sediments: An investigation by low-field NMR

Theoretical Prediction of the Occurrence of Gas Hydrate Stability Zones: A Case Study of the Mohe Basin, Northeast China

Determining Triaxial Stress Sensitivity of Oil Reservoir Rocks without Fluid Flooding

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