Summary
This paper presents the results of a project that was initiated to analyze
the inflow performance and inflow distribution of one smart and two problematic
conventional, long, and tortuous horizontal wells in Brunei.
Following a detailed hydraulic analysis of these wells, a good match with
field measurements was obtained. Simulation results show that the problems in
the conventional wells were not as severe as those interpreted from the
measurements of distributed temperature sensing systems (DTSs). It is also
demonstrated that the compartmentalized completion with inflow control valves
(ICVs) in the smart well has added value, because the well would not be
producing from over half of the reservoir section without the smart
completion.
Introduction
Brunei Shell Petroleum (BSP) is a keen implementer of wells with
sophisticated trajectories for achieving maximum reservoir exposure. The aim is
to drain oil from stacked sand bodies that cannot be produced economically via
separate dedicated wells. These wells have long reservoir sections of up to 3
km with undulations of up to 40 m. Some of them are equipped with distributed
temperature-sensing technology for monitoring the inflow distribution, and some
have smart completions to control inflow from different reservoir sections and
to assist with well cleanup. Interpretation of the DTS traces indicated
inflow-performance problems in the long conventional producers, whereas the
smart wells were observed to be flowing over at approximately their full
length. Inadequate well cleanup was thought to be the primary cause of the
problematic inflow performance of the conventional wells. A detailed hydraulic
analysis of two problematic conventional wells and one smart well was requested
by BSP to understand the inflow problems in the conventional producers and to
confirm the justification for smart completions.
Because the initial kickoff and cleanup are highly transient processes
(Mantecon et al. 2004), a transient multiphase-flow simulator was used for
modelling. The wells were simulated from initial startup until early in their
production life, which included mud removal and stabilized wellbore flow. In
both of the conventional wells, calculated flow rates and pressures agreed with
the available well test measurements. Simulation results have shown longer
producing intervals than those derived from the DTS traces. The main reason for
this could be that the limited flow coming from the toe section in a horizontal
well causes a minor temperature disturbance, which can be overlooked easily in
the DTS traces (Ouyang and Belanger 2006). Good results from the initial
calculations, gave enough confidence to continue with the smart well; a
more-complicated case from the modelling point of view.
Because the smart well had not been tested in the early stages of
production, only the recorded pressures from the permanent downhole pressure
gauge (DHPG) were used to validate the model. Calculated flowing bottomhole
pressures (FBHPs) agreed with the measurements. Simulations have shown that the
smart completion gives an opportunity to produce the well over the full length.
A sensitivity analysis was performed by removing the smart completion from the
model. Results justified the smart completion because the well would be
producing from only half of the reservoir section if it were completed
conventionally.
Results of this work have provided enough confidence to use the same
modelling approach in design and operation of future wells with complicated
trajectories and architecture. This modelling approach could also be of value
for a more-adequate interpretation of DTS measurements and better understanding
of how the smart completion helps to increase the producing interval over a
long well section.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
26 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
4 February 2008
- Manuscript approved:
4 April 2008
- Version of record:
15 November 2008
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