Numerical modeling for drilling fluid invasion into hydrate-bearing sediments and effects of permeability

Drilling fluid invasion into hydrate-bearing sediments could induce hydrate dissociation and complicate heat and mass transfer around wellbore, and further affect mechanical strength of hydrate-bearing sediments and accurateness of wellbore logging interpretations. In this study, a cylindrical numer...

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Bibliographic Details
Published in:Journal of Natural Gas Science and Engineering
Main Authors: Huang, Tianjia, Zhang, Yu, Li, Gang, Li, Xiaosen, Chen, Zhaoyang
Format: Report
Language:English
Published: ELSEVIER SCI LTD 2020
Subjects:
Natural gas hydrate
Drilling fluid invasion
Hydrate dissociation
Secondary hydrate
Permeability
SEA-WATER SOLUTIONS
GAS-HYDRATE
METHANE-HYDRATE
SHENHU AREA
RELATIVE PERMEABILITY
WELLBORE INSTABILITY
PHYSICAL-PROPERTIES
STABILITY
DISSOCIATION
SATURATION
Energy & Fuels
Engineering
Chemical
Corey
Methane hydrate
Online Access:http://ir.giec.ac.cn/handle/344007/26711
https://doi.org/10.1016/j.jngse.2020.103239
Description
Summary:Drilling fluid invasion into hydrate-bearing sediments could induce hydrate dissociation and complicate heat and mass transfer around wellbore, and further affect mechanical strength of hydrate-bearing sediments and accurateness of wellbore logging interpretations. In this study, a cylindrical numerical model was established to study the characteristics of drilling fluid invasion into hydrate-bearing sediments and the effects of permeability on this process. The distributions of temperature, pressure, saturation, and salinity of pore water around wellbore at different time were obtained. The pressure and temperature around wellbore gradually increase, and the hydrate around wellbore dissociates with the high-temperature drilling fluid invasion. Meantime, water and gas generated from hydrate dissociation gradually migrate outward and then form 'secondary hydrate' in some areas outside wellbore. Dissociation and formation of hydrate can sharply change the salinity of pore water around wellbore. The drilling fluid invasion and hydrate dissociation ranges become larger when the intrinsic permeability is higher. The salinity in sediments decreases sharply while the dilution range is narrow when drilling fluid invasion into hydrate-bearing sediments with low permeability. In addition, the permeability decline exponent of the Masuda model has a significant influence on drilling fluid invasion. However, the Corey exponents of the relative permeability model only have a limited influence on drilling fluid invasion into hydrate-bearing sediments with low intrinsic permeability (e.g., 5.5 mD), while they have a noticeable influence on hydrate-bearing sediments with high intrinsic permeability (e.g., 75 mD).

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