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Research Papers: Petroleum Engineering

Analysis of Wellbore Temperature Distribution and Influencing Factors During Drilling Horizontal Wells

[+] Author and Article Information
Zheng Zhang

State Key Laboratory of Oil and Gas Reservoir
Geology and Exploitation,
Southwest Petroleum University,
Chengdu 610500, Sichuan, China
e-mail: zhangzhengswpu@163.com

Youming Xiong

State Key Laboratory of Oil and Gas Reservoir
Geology and Exploitation,
Southwest Petroleum University,
Chengdu 610500, Sichuan, China
e-mail: xiongyoum@qq.com

Fang Guo

State Key Laboratory of Oil and
Gas Reservoir Geology and Exploitation,
Southwest Petroleum University,
Chengdu 610500, Sichuan, China
e-mail: 1273227418@qq.com

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received December 11, 2017; final manuscript received March 5, 2018; published online April 16, 2018. Assoc. Editor: Mohamed A. Habib.

J. Energy Resour. Technol 140(9), 092901 (Apr 16, 2018) (11 pages) Paper No: JERT-17-1700; doi: 10.1115/1.4039744 History: Received December 11, 2017; Revised March 05, 2018

Horizontal well drilling technology is widely used in the exploitation of petroleum and natural gas, shale gas, and geothermal resources. The temperature distribution of wellbore and surrounding formation has a significant influence on safe and fast drilling. This study aims to investigate the temperature distribution of horizontal wellbores during circulation by using transient temperature model. The transient temperature prediction model was established by the energy conservation law and solved by the relaxation iterative method. The validity of the model has been verified by the field data from the Tarim Oilfield. The calculation results showed that the highest temperature of the drilling fluid inside the drill string was at the bottomhole and the highest temperature of annulus drilling fluid was at some depth away from the bottomhole. Sensitivity analysis of various factors that affect the temperature distribution of annulus drilling fluid were carried out, including the circulation time, the flow rate, the density of drilling fluid, the inlet temperature, the vertical depth, the horizontal section length, and the geothermal gradient. It can be found that the vertical depth and the geothermal gradient have a significant influence on the bottomhole temperature, and inlet temperature plays a decisive influence on the outlet temperature. These findings can supply theoretical bases for the horizontal wellbore temperature distribution during drilling.

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Figures

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Fig. 1

Wellbore and formation heat transmission model of horizontal well during circulation

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Fig. 2

The comparison between the field tests results and the calculated results of well no. 1

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Fig. 3

Wellbore temperature distribution after circulation for 24 h

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Fig. 4

Influence of the changes of the circulation time on the annulus drilling fluid temperature distribution

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Fig. 5

Influence of the changes of the circulation time on the wellhead temperature

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Fig. 6

Influence of the changes of the circulation time on the bottom hole temperature

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Fig. 7

Influence of variations in the flow rate on the annulus drilling fluid temperature distribution

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Fig. 8

Influence of variations in the drilling fluid density on the annulus drilling fluid temperature distribution

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Fig. 9

Influence of variations in the inlet temperature of drilling fluid on the annulus drilling fluid temperature distribution

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Fig. 10

Influence of variations in the vertical depth on the annulus drilling fluid temperature distribution

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Fig. 11

Influence of variations in the horizontal section length on the annulus drilling fluid temperature distribution

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Fig. 12

Influence of variations in the geothermal gradient on the annulus drilling fluid temperature distribution

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Fig. 13

The rate of change of bottom hole temperature when different influence factors change by one percent, respectively

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Fig. 14

The rate of change of outlet temperature when different influence factors change by 1%, respectively

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Fig. 15

The diagram of mesh grids of the wellbore and formation

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Fig. 16

The flowchart of numerical model solution

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