Summary
A total-system production-optimization model has been implemented in a
complex gas lifted offshore operation, resulting in production gains and
operating-cost reductions. Whereas previous optimization models considered only
the wells and production-gathering network, the new model is able to consider
the combined performance of the total system, including downhole well
configurations, the complex production-gathering and lift-gas-distribution
pipeline networks, separators, compressors, and pumps. The model is applicable
to most gas lifted fields and will be particularly beneficial when applied to
those with complex production systems, and those where compressors are a
constraint on total-system performance.
The output from the optimization model principally comprises recommended
values for individual-well gas lift injection rates, separator pressures,
compressor discharge pressures, and compressor use. Field results are presented
in this paper to demonstrate how implementing the optimizer’s recommendations
in the field resulted in economic benefits through increased production and
reduced operating costs. Also described is how the model allows field
operations engineers to reoptimize field control parameters on a more frequent
basis and with less manpower than previously.
The successful implementation of a complex model with such a broad scope is
as dependent on the implementation process as it is on the technology.
Therefore, in addition to describing the details of the model itself, this
paper will cover the issues that arose during the implementation and how they
were resolved. These include the level of manpower and support required,
project organization and execution, and the processes required to sustain the
benefits after the initial optimization gains have been realized.
Introduction
Dubai Petroleum Company (DPC) has implemented a production-optimization tool
that has yielded production gains and operating-cost reductions. The
field-otpimization software is used to model the complex production networks
associated with the gas lifted fields, including the downhole well
configurations and the surface-facility components such as gas-compressor
trains, pipelines, and surface pumps. Key benefits realized from all fields
were a 3% total production increase, a 4% reduction in lift-gas requirements,
and a 3% reduction in operating costs. Field operations support was critical to
the project’s success by tracking the operational parameters continuously
throughout implementation to validate the recommendations and results.
The project was planned to be executed in three phases, including a pilot
study to assess the value of a full-field model and to identify and resolve
implementation challenges. The full-field model was implemented during 2003 and
produced several key learnings about the level of manpower and support
required, the importance of accurate well-model tuning, and the value that a
detailed compressor model can add to a system highly dependent on compressor
efficiency. Challenges associated with the gas lift control systems, which are
nearing obsolescence, were also identified and created a need for alternative
strategies depending on the length of time that the gas lift rate reallocation
would be in effect.
The full-field optimization process uses an integrated approach to address
operational challenges. A team of engineers and operations personnel now
manages events proactively on the basis of a well-defined strategy. The
optimization model has allowed gas lift reallocations to be performed on a more
frequent basis and with less manpower. On the basis of these reallocations,
production increases have been realized and the fields are currently operating
at the historically lowest separator pressures. Offline studies have been
performed to recommend process-equipment modifications and justify major
equipment overhauls. The integrated network model has also been used as a
predictive tool to forecast the impact of ambient conditions and scheduled
maintenance on production rates. The results are being monitored currently to
determine the value of adding a fully automated interface to the system-model
software package.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
21 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
8 May 2007
- Manuscript approved:
16 May 2007
- Version of record:
20 February 2008
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