Effect of Drilling Fluid Invasion on Natural Gas Hydrate Near-Well Reservoirs Drilling in a Horizontal Well

Qibing Wang,Jie Yang,Kaihe Lv,Yuanzhi Qu,Jinsheng Sun,Jianlong Wang,Jintang Wang,Ren Wang,Cheng Lu,Jiaxin Sun

doi:10.3390/en14217075

Abstract

Horizontal wells can significantly improve the gas production and are expected to be an efficient exploitation method for the industrialization of natural gas hydrates (NGHs) in the future. However, the near-wellbore hydrate is highly prone to decomposition during the drilling process, owing to the disturbance aroused by the factors such as the drilling fluid temperature, pressure, and salinity. These issues can result in the engineering accidents such as bit sticking and wellbore instability, which are required for further investigations. This paper studies the characteristics of drilling fluid invasion into the marine NGH reservoir with varied drilling fluid parameters via numerical simulation. The effects of the drilling fluid parameters on the decomposition behavior of near-wellbore hydrates are presented. The simulating results show that the adjustments of drilling fluid density within the mud safety window have limited effects on the NGH decomposition, meanwhile the hydrates reservoir is most sensitive to the drilling fluid temperature variation. If the drilling fluid temperature grows considerably due to improper control, the range of the hydrates decomposition around the horizontal well tends to expand, which then aggravates wellbore instability. When the drilling fluid salinity varies in the range of 3.5–7.5%, the increase in the ion concentration speeds up the hydrate decomposition, which is adverse to maintaining wellbore stability.

Highlights

Natural gas hydrates (NGHs), the solid cage-like compounds formed by natural gas and water under low-temperature and high-pressure [1,2,3] conditions, are mainly found at the subsea formation of the continental shelve margin or in the permafrost of cold regions [4,5,6,7]
The distributions are a square far from the wellbore because the mesh node results are interpolated from the mesh center node information that provided by TOUGH + HYDRATE, noting that pore pressure can quickly respond if the pressure balance is broken after drilling
The drilling fluid invasion and hydrate decomposition leads to the increase of reservoir water cut, which impairs the cohesion between the sediment particles and further reduces the reservoir mechanics, especially the shear strength [50,51]

Summary

Introduction

Natural gas hydrates (NGHs), the solid cage-like compounds formed by natural gas and water under low-temperature and high-pressure [1,2,3] conditions, are mainly found at the subsea formation of the continental shelve margin or in the permafrost of cold regions [4,5,6,7]. Supposing that the drilling fluid properties were not well-regulated, it could trigger gas hydrate decomposition in the reservoir, which degrades the physical properties of the reservoir and could cause wellbore instabilities [22,23,24,25]. To investigate this type of issue, many scholars have established mathematical models to study the invasion of drilling fluid in hydrate formation. Afterwards, a two-dimensional cementing model was established by Zheng [31] in order reproduced the cement slurry invasion process with TOUGH + HYDRATE and analyzed the physical property response of hydrate reservoir in the cementing process according to the numerical simulation data

Objectives

Results

Conclusion