Numerical simulations of depressurization-induced gas production from an interbedded turbidite gas hydrate-bearing sedimentary section in the offshore India: Site NGHP-02-16 (Area-B)

Myshakin, Evgeniy M.; Seol, Yongkoo; Lin, Jeen-Shang; Uchida, Shun; Collett, Timothy S.; Boswell, Ray

doi:10.1016/j.marpetgeo.2018.10.047

Cited by 77 publications

(30 citation statements)

References 46 publications

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“…Hydrate in porous media reduces the pathways available for flow of fluid phases (water and gas), and as reviewed by You et al (2019), understanding this reduction is needed to assess formation and model production of hydrate reservoirs (e.g., Moridis et al, 2009; Myshakin et al, 2019). Emplacement of hydrate can be considered a change in the pore space with related changes in porosity and permeability (e.g., Dai et al, 2012; Waite et al, 2009); models to predict reductions in permeability and porosity due to hydrate formation have been built under this concept (Liu & Flemings, 2006; Moridis et al, 2019; Nimblett & Ruppel, 2003).…”

Section: Introductionmentioning

confidence: 99%

Hydrate is a Nonwetting Phase in Porous Media

Murphy

DiCarlo²,

Flemings

et al. 2020

Geophysical Research Letters

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In porous media containing gas hydrate, the hydrate morphology impacts the flow behavior of the fluid phases. We hypothesize that hydrate emplaces itself as a nonwetting phase and use this idea to describe relative permeability of water in a hydrate/water system. We perform steady‐state relative permeability measurements in hydrate‐bearing samples with a range of hydrate saturation. We measure and compare water relative permeability in the presence of gas and in the presence of hydrate and find that the water relative permeability is the same in both cases. This suggests that (1) relative permeability for hydrate systems can be obtained without performing difficult experiments on hydrate bearing sediments, (2) flow properties are porous‐media dependent, and (3) models that assume a fixed pore or tube geometry are inadequate.

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Section: Introductionmentioning

confidence: 99%

Hydrate is a Nonwetting Phase in Porous Media

Murphy

DiCarlo²,

Flemings

et al. 2020

Geophysical Research Letters

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“…Although relative permeability of conventional reservoir rocks has been studied for a long time 11,12 , to our knowledge, there seems to be no peer-reviewed literature on experimental relative permeability of combined gas and brine flow in hydrate-bearing sediments. Numerical simulations of gas hydrate uses empirical models [13][14][15][16] (e.g. B-C, van Genuchten, etc.)…”

Section: A Novel Relative Permeability Model For Gas and Water Flow Imentioning

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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“…Consequently, many investigations (eg, Refs. [17][18][19][20][21][22][23][24][25][26][27][28][29][30][31][32][33] have been performed recently, and numerical simulations have still focused on depressurization that is aimed at commercial production from potential target areas. In practice, depressurization has also been widely adopted in field trials in Mallik, 34 the eastern Nankai Trough, 35,36 and the South China Sea.…”

Section: Introductionmentioning

confidence: 99%

Gas production from a silty hydrate reservoir in the South China Sea using hydraulic fracturing: A numerical simulation

Sun

Ning

Liu

et al. 2019

Energy Science & Engineering

108

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The low permeability of silty hydrate reservoirs in the South China Sea is a critical issue that threatens safe, efficient, and long‐term gas production from these reservoirs. Hydraulic fracturing is a potentially promising stimulation technology for such low‐permeability reservoirs. Here, we assess the gas production potential of a depressurization horizontal well that is assisted by the hydraulic fracturing using numerical simulation according to field data at site SH2 in this area. In addition, the number of horizontal wells drilled is discussed if commercial production is to be performed at this site. The results show that the production potential can be significantly stimulated at the early production stage by adopting hydraulic fracturing in this reservoir due to a better depressurization effect. However, the increase in gas recovery gradually decreases with the continuous dissociation of gas hydrates, and the evolution trend is similar to that in a reservoir without stimulation during later periods of gas production because the dissociation front gradually moves away from the fractures. From the perspective of production potential, using a horizontal well scheme assisted by the hydraulic fracturing technology for gas recovery from a hydrate deposit can sharply reduce the number of operation wells, shorten the drilling operation time, and boost the economic efficiency. The horizontal well scheme may be an effective way to increase the gas yield if the application of quickly deployed horizontal wells and hydraulic fracturing techniques in such hydrate reservoirs greatly increases in the near future.

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Numerical simulations of depressurization-induced gas production from an interbedded turbidite gas hydrate-bearing sedimentary section in the offshore India: Site NGHP-02-16 (Area-B)

Cited by 77 publications

References 46 publications

Hydrate is a Nonwetting Phase in Porous Media

Hydrate is a Nonwetting Phase in Porous Media

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

Gas production from a silty hydrate reservoir in the South China Sea using hydraulic fracturing: A numerical simulation

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