Summary
Knowing the exact flow allocation for each controlled zone is important for
well optimization and the management of an intelligent well system (IWS). For
two-zone IWS producers, a broadly accepted downhole gauge configuration uses
the triple-gauge system, where two gauges give the upstream-side
pressure/temperature (P/T) of the two downhole control valves and one gauge
gives the P/T inside tubing of the commingled fluid [Baker Hughes IWS
installation (2012) and Halliburton-WellDynamics IWS installation (2012)
databases]. Theoretically, this configuration gives the P/T boundary conditions
between the two valves and the gauge carrier, where flow allocations can be
solved numerically, on the basis of the gauge readings and control-valve
settings. However, from what we have seen in the past 10 years of IWS
applications, only a few have published successful application cases regarding
this topic. Is this an indication that a large number of two-zone triple-gauge
IWS wells are operating in the low-confidence region of the two zone's
production flow allocations?
In this work, a comprehensive hydraulic model has been developed to address
this topic. This paper will discuss a recent application of such a model to
estimate the flow allocations of an existing two-zone deepwater IWS oil
producer. The well began production in 2007. A total of 1,362 daily
triple-gauge data points are available for this study, where the monitored P/T
data indicate that the well was flowed in multiphase conditions at downhole for
a large percentage of its production life. Verification was completed by
comparing the predicted flow-allocation results with this well's measured total
rates and daily-allocation rates. Further comparisons of the zonal allocations,
between the model calculated results vs. the zonal-reservoir
deliverability-study predicted results, were also provided. These comparisons
showed a good match between the predicted results, measured data, and the
available reservoir-study results. Descriptions of key factors to address the
accuracy of the method have been provided, including compensated differential
pressure, multiphase choke model, choke-discharge coefficient, and fluid
pressure/volume/temperature (PVT) behavior impact. Sun's modified multiphase
choke model was proposed in this study. The authors believe it will be more
suitable for downhole valve operating and multiphase-flow conditions.
This case study has proven a very promising independent solution for
continuous well-rate estimation, with the solution based purely on
choke-pressure drops and intelligent well-valve positions. The downhole
monitoring P/T is normally based on seconds, which means that intelligent
well-flow allocations can be calculated in real time without installing
downhole venturi flowmeters that may add completion cost. In addition, a
venturi flowmeter provides a smaller ID profile for the completion strings
above/below it, which is inconvenient for future potential wellbore
interventions. This solution brings measurable benefits for those IWS wells
with no downhole flowmeters when taking into account the time and effort spent
on periodic production tests, reservoir/well deliverability studies for
production allocations, and potential production loss during the production
tests.
© 2012. Society of Petroleum Engineers
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History
- Original manuscript received:
27 February 2011
- Meeting paper published:
20 April 2011
- Revised manuscript received:
24 January 2012
- Manuscript approved:
22 February 2012
- Published online:
30 May 2012
- Version of record:
11 June 2012
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