Interpretation of temperature transient data from coupled reservoir and wellbore model for single phase fluids

Cihan Alan, Murat Cinar*

*Corresponding author for this work

Research output: Contribution to journalArticlepeer-review

8 Citations (Scopus)

Abstract

This paper presents a non-isothermal, transient coupled reservoir/wellbore model that accounts for the Joule-Thomson (J-T), isentropic expansion, conduction and convection effects for predicting the transient temperature behavior and computing the wellbore temperature at different gauge depths. In this study, single phase fluid flow of oil or geothermal brine from a fully penetrating vertical or inclined well in an infinite-acting homogeneous single layer reservoir is modeled. The coupled simulator solves mass, momentum and energy conservation equations simultaneously for both reservoir and wellbore. We improve solutions by the functional iteration procedure that updates fluid properties based on available correlations as a function of pressure and temperature at a given time step. A comparison of the developed model with a commercial simulator is provided. To understand and identify diagnostic characteristics of temperature transients at gauge locations at the sandface and above the sandface that may arise during a well test, we examine the sensitivity of the model parameters appearing in the coupled non-isothermal reservoir/wellbore model through a synthetically generated test data sets and history matched field application. The drawdown and buildup sandface transient temperature data are obtained from the coupled model and used to interpret and analyze temperature transients. In addition to the J-T coefficient of fluid, history matching transient temperature data provides estimates for the skin zone radius and permeability when analyzed jointly with the conventional pressure test analysis (PTA). An investigation on the effect of gauge location on temperature data shows that the early-time response is influenced by the wellbore phenomena while the J-T effects are clearly identified at later times at typical gauge locations up to 100 m above the top of the producing horizon. Logarithmic derivative of temperature transients are found as a useful diagnostic tool to differentiate the wellbore phenomena from the reservoir response. It is also shown that the temperature transient is more reflective of the properties of the near wellbore region (e.g., skin zone) than the pressure transient. For this reason, analyzing temperature transients together with the pressure transients could add more value to the analysis to better examine near wellbore characteristics.

Original languageEnglish
Article number109913
JournalJournal of Petroleum Science and Engineering
Volume209
DOIs
Publication statusPublished - Feb 2022

Bibliographical note

Publisher Copyright:
© 2021 Elsevier B.V.

Funding

The authors thank Professor Mustafa Onur of the University of Tulsa, USA for his valuable support. The authors thank Computer Modeling Group for providing CMG-STARS and Kappa Engineering for providing Saphir to Petroleum and Natural Gas Engineering of Istanbul Technical University (ITU) for educational purposes.

FundersFunder number
University of Tulsa
Istanbul Teknik Üniversitesi

    Keywords

    • History matching
    • Numerical simulation
    • Parameter estimation
    • Sensitivity analysis
    • Temperature transients
    • Well testing

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