Summary
Permanent downhole monitoring can provide valuable information for
production decisions in real time without the need to perform an intervention
to collect data. One of the commercial permanent monitoring technologies is the
fiber-optic DTS, which can record the wellbore temperature profile in real time
with decent accuracy and resolution. A key potential application for DTS data
is to profile injection or production for wells, which is the primary
motivation and focus of this project.
In the present paper, a thermal model recently developed for single-phase-
and multiphase-fluid flow along a vertical, deviated, or horizontal well will
first be briefly described. The model can be applied for both wellbore
temperature prediction (forward modeling) and for flow profiling using a
measured temperature profile (inverse problem).
The model has successfully been applied for investigating key thermal
characteristics of single-phase- and multiphase-fluid flow along a wellbore. In
particular, the dependence of wellbore temperature upon phases, flow profile,
fluid type, fluid properties, well deviation, and Joule-Thomson effect will be
demonstrated in the paper. The model has further been adapted for directly
predicting production and injection profiles (i.e., flow profiling) based on a
given wellbore temperature profile. The potential impact of noise in the DTS
measurement on flow profiling has been explored.
It is found that the wellbore temperature does not change significantly
along horizontal or near-horizontal sections because of the small variation in
geothermal temperature. Therefore, based only on steady-state DTS data, the
amount and the location of each fluid entry would be difficult to identify. The
current study shows that a maximum wellbore deviation of 75° should be honored
to appropriately estimate flow profile directly through steady-state DTS data.
The study has also led to an observation that under certain circumstances such
as multiphase flow, a production profile may be determined through DTS
temperature measurement with extra data or information provided. The types of
the extra measurements and the appropriate approaches will be recommended.
Introduction
The DTS system has become a compelling piece of equipment to be considered
for permanent downhole monitoring design. DTS provides real-time temperature
profile measurement, which can enhance understanding of the flow downhole. DTS
systems have been installed all over the world (Johnson et al. 2004; Brown et
al. 2005; Tolan et al. 2001; Brown et al. 2004; Brown et al. 2000; Kragas et
al. 2001; Lanier et al. 2003; Fryer et al. 2005; Kluth et al. 2000; McKay et
al. 2000)—including the North Sea, the Gulf of Mexico, Asia Pacific, Mexico,
Venezuela, Texas, and California, to name a few—for steam breakthrough
detection, water and gas injection management, production profiling,
behind-pipe flow diagnostics, and reservoir surveillance.
Flow profiling by temperature log can be traced back to the 1960s and 1970s,
when a couple of techniques (Ramey 1962; Curtis and Witterholt 1973;
Romero-Juárez 1969) were proposed to quantitatively estimate flow rates at
various wellbore positions. The techniques are based on analytical solutions
[e.g., the Ramey solution (Ramey 1962)] and have not gained much success
because of certain limitations associated with temperature acquisition, data
resolution, and the techniques themselves. More details can be found in SPE
Monograph No. 14 (Hill 1998).
Similar thinking has been extended to single-phase and multiphase flow along
more complex wellbore configurations. Models, procedures, and applications have
been developed for wellbore temperature profile prediction and flow profiling
through temperature logs. Partial details will be documented in the present
paper. The focus will be on the impact of fluid phase on wellbore temperature
profiles as well as exploring the scenarios where it is feasible to predict
flow profiles with temperature logs. Addressing these issues would help
petroleum engineers set realistic expectations for a DTS system that can easily
take up a significant portion of well Capex expenditures.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
14 August 2004
- Revised manuscript received:
29 August 2005
- Manuscript approved:
29 August 2005
- Version of record:
20 May 2006
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