Laboratory validation of effective acoustic velocity models for samples bearing hydrates of different type

Дугаров, Г. А.; Duchkov, Anton A.; Дучков, А. Д.; Drobchik, Arkady N.

doi:10.1016/j.jngse.2019.01.007

Cited by 37 publications

(13 citation statements)

References 40 publications

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“…So it is clearly beneficial to combine the laboratory experiments on forming and studying hydrate-bearing samples with their imaging at different scales. For example, different scenarios of hydrate formation result in different hydrate morphology in pore filling, which considerably affects acoustic macro-properties (Waite et al, 2009;Priest et al, 2009;Dugarov et al, 2019): non-cementing (pore-filling) hydrate formation does not affect acoustic velocities much, while cementing hydrate formation type results in a faster increase of acoustic velocities. X-ray Computed Tomography (CT) is widely used to image the detailed structure of rocks which have a complicated porous structure consisting of materials very different in properties: mineral particles, gas, multi-phase liquids.…”

Section: Introductionmentioning

confidence: 99%

Dynamic in-situ imaging of methane hydrate formation and self-preservation in porous media

Никитин

Дугаров

Duchkov

et al. 2020

Marine and Petroleum Geology

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Section: Introductionmentioning

confidence: 99%

Dynamic in-situ imaging of methane hydrate formation and self-preservation in porous media

Никитин

Дугаров

Duchkov

et al. 2020

Marine and Petroleum Geology

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“…A possible reason hypothesized by the noted studies attributes this deviation to tortuosity of gas flow. The deviation in k rg increases with increase of S h , which could indicate change in gas hydrate morphology 3,41 . A possible reason for the increase in deviation of k rg at high S h is possibly due to a shift from pore filling (at intermediate S h < 40%) to other morphologies (e.g.…”

Section: Discussionmentioning

confidence: 98%

“…Gas hydrate morphologies are widely described in terms of pore filling (PF), grain coating, load bearing, etc. 3,[38][39][40][41] , especially for pore-scale studies. Field-scale studies indicate that in sandy gas hydrate deposits a dominant precipitation habit of gas hydrate is PF 3,39 .…”

Section: Approachmentioning

confidence: 99%

A Novel Relative Permeability Model for Gas and Water Flow in Hydrate-Bearing Sediments With Laboratory and Field-Scale Application

Singh

Myshakin

Seol

2020

Sci Rep

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In a producing gas hydrate reservoir the effective porosity available for fluid flow constantly changes with dissociation of gas hydrate. Therefore, accurate prediction of relative permeability using legacy models (e.g. Brooks-Corey (B-C), van Genuchten, etc.) that were developed for conventional oil and gas reservoirs would require empirical parameters to be calibrated at various Sh over its range of variation, but such calibrations are precluded because of lack of experimental relative permeability data. This study proposes a new relative permeability model for gas hydrate-bearing media that is a function of maximum capillary pressure, capillary entry pressure, pore size distribution index, residual saturations, hydrate saturation, and four other constants. The three novel features of the proposed model are: (i) requires fitting its six empirical parameters only once using experimental data from any single Sh, and the same set of empirical parameters predict relative permeability at all Sh, (ii) includes the effect of capillarity, and (iii) includes the effect of pore-size distribution. From practical standpoint, the model can be used to simulate multiphase flow in gas hydrate-bearing sediments where the proposed relative permeability can account for the evolving hydrate saturation. The proposed model is implemented in a numerical simulator and the wall time required to perform simulations using the proposed model is shown to be similar to the time it takes to run same simulations with the B-C model. The proposed model is a step forward towards achieving the goal of physically accurate modeling of multiphase flow for gas hydrate-bearing sediments that accounts for the effect of gas hydrate saturation change on relative permeability.

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“…Results in Figure can be summarized in the following three points: (i) lower k rg in pore‐filling hydrates suggests that gas is more resistive in pore‐filling hydrates than in grain‐coating hydrates, (ii) although k rw shows little sensitivity to hydrate morphology, grain‐coating hydrates have the lowest k rw than the other two morphologies at higher S h (≥0.6), which suggests that grain‐coating hydrates will have the lowest mobility of water at higher S h , and (iii) maximum relative permeability of water is always higher than maximum relative permeability of gas inside pore‐filling hydrates, while maximum relative permeability of gas is always higher than maximum relative permeability of water inside grain‐coating hydrates. The morphology of hydrates in a reservoir can be characterized using conventional sonic well logs (Dugarov et al, ; Helgerud et al, ; Konno et al, ; Waite et al, ), specifically compressional ( P wave) velocity that shows a higher velocity for grain‐coating hydrates (Murray et al, ). The capillary pressure of fluids in contact with hydrate is expected to be different compared to the capillary pressure of fluids in contact with grain sediments; this demarcation is necessary for accurate estimation of the relative permeability by considering capillarity effect and hydrate morphology.…”

Section: Discussionmentioning

confidence: 99%

A Mechanistic Model for Relative Permeability of Gas and Water Flow in Hydrate‐Bearing Porous Media With Capillarity

Singh

Mahabadi

Myshakin

et al. 2019

Water Resources Research

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Lack of mechanistic models to describe petrophysical properties of mobile phases in gas hydrate‐bearing sediments is one of the key challenges in accurately predicting gas production. The major drawback of empirical models that are used to fit a relative permeability curve for mobile phases in gas hydrate‐bearing sediments is that they are based on experimental data, which are limited, and not able to account for hydrate morphology in pore space. This study proposes a relative permeability model that is mechanistic in nature and developed to account capillarity by building on the original nonempirical relative permeability model that assumes negligible capillary pressure. The proposed model implicitly accounts for capillarity with the help of four empirical parameters (two for each mobile phase) that incorporate each mobile phase pressure. It is shown that the proposed model provides an improved match to relative permeability data (derived from pore‐scale simulation of gas hydrate‐bearing sediments) than nonempirical relative permeability by accounting for the effect of capillary pressure. Additionally, unlike fully empirical models that can predict relative permeabilities reliably only at gas hydrate saturations for which experimental data are available, the proposed model only requires fitting the empirical parameters once with experimental data at any single gas hydrate saturation and then it can then be used to predict relative permeability at any gas hydrate saturation. The mechanistic nature of the proposed model allows studying relative permeability of hydrate‐bearing sediments as a function of hydrate morphology and wettability (fluid phase distribution) besides other physical parameters of the model (e.g., porosity, gas, and water residual saturation). Based on the sensitivity analysis of different hydrate morphologies on gas/water relative permeability, it is found that gas relative permeability is sensitive to hydrate morphologies, while water relative permeability shows little dependency on hydrate localization in pore space.

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Laboratory validation of effective acoustic velocity models for samples bearing hydrates of different type

Cited by 37 publications

References 40 publications

Dynamic in-situ imaging of methane hydrate formation and self-preservation in porous media

Dynamic in-situ imaging of methane hydrate formation and self-preservation in porous media

A Novel Relative Permeability Model for Gas and Water Flow in Hydrate-Bearing Sediments With Laboratory and Field-Scale Application

A Mechanistic Model for Relative Permeability of Gas and Water Flow in Hydrate‐Bearing Porous Media With Capillarity

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