Summary
A four-zone intelligent water-alternating-gas (WAG) injector was installed
at the Statoil Veslefrikk Field in the North Sea in May 2004. The completion
includes one on/off and three variable downhole chokes for controlling
injection rate into each of the four zones. The completion also includes three
downhole optical flowmeters and three optical pressure and temperature gauges.
Measurement of surface injection rate and the rate from each of the three
flowmeters provides real-time measurement of injection rate into each zone,
regardless of choke positions.
The well is on a WAG cycle in which one zone is primarily intended for gas
injection and the other three zones are primarily intended for water injection.
Therefore, equipment that can control and measure water flow and gas flow with
no changes in hardware was critical for the success of this installation.
The combination of downhole chokes and flowmeters allows full control and
monitoring of zonal injection rates and has proved to be a valuable tool for
managing reservoir pressures and optimizing production. After more than 1 year
of operation during water injection, all the valves and the optical monitoring
equipment are functioning satisfactorily. It is estimated that up to half of
the well’s value creation during its expected lifetime is because of the DIACS
(Downhole Instrumentation and Control System) installation.
Introduction
Production optimization is traditionally associated with maximizing the
performance of a producing well by control of the wellhead choke, electric
submersible pumps (ESPs), or gas lift rate. Conversely, water or gas (or WAG)
injectors have traditionally been used to maintain reservoir pressure, but have
not typically been used in a structured production optimization program.
However, use of multizone intelligent injectors with downhole flow control and
monitoring is shifting this paradigm.
It is widely recognized that real-time, downhole flow control and
measurement is critical for production optimization in complex intelligent
completions and in dual and multilateral wells. Applications include zonal
production or injection allocation in multizone completions, increased accuracy
of injection profiles, and in producing wells, the ability to commingle
production from multiple zones and reduce or eliminate surface well tests and
facilities.
It is critical for the successful implementation of intelligent wells that
reliable downhole flow control and monitoring equipment be used. The nature of
downhole monitoring and control systems renders them inaccessible after
installation, and therefore repair or replacement of faulty downhole equipment
normally means pulling the entire completion.
Monitoring equipment ranges from downhole electronic pressure and
temperature gauges to downhole optical single- and multiphase flowmeters.
Downhole monitoring equipment is normally designed for life-of-well; however,
in practice, many technologies fail to deliver on this promise and stop working
after only a few months in the well. In recent years, and especially with the
advent of fiber-optic sensing, the reliability picture is changing. In
electronic systems, the reliability of monitoring equipment deteriorates
rapidly with increasing temperatures, although vendors are continually
introducing new products that address high-temperature issues. In
low-temperature wells, both electronic and optical systems have proven records
of years of reliable operation.
In addition, the operator needs a reliable control valve system to allow
adjustments and to fine-tune production or injection. Sensors provide data
which help identify recovery potential, but a reliable flow control system can
turn that potential into real value by providing the operator with reservoir
management options which do not require costly well intervention. Some
operators consider the real value of production optimization technology to be
the ability to reconfigure the flow profile remotely without intervention.
Early in the development of downhole production optimization technology, the
high price of the systems combined with poor reliability was of primary concern
to operators.
Most operators associated downhole electronics and complexity used in the
early systems with high potential workover cost. From the adoption of the early
systems to date, there has been a dramatic improvement in reliability. Today,
the reliability of these systems is proven, and they are seeing market
acceptance and wider application.
© 2007. Society of Petroleum Engineers
View full textPDF
(
4,241 KB
)
History
- Original manuscript received:
14 July 2005
- Manuscript approved:
15 June 2006
- Version of record:
20 May 2007
View Cart
