“Real time” is the new buzz in the upstream petroleum industry. So far,
operators at the lease location have been the main users of real-time data
measured at second or minute increments to manage wells and keep them on
production. Engineers usually see only a subset of the data—the daily
production volumes and rates, along with a few selected gauge-pressure and
temperature readings. The engineers’ access to limited data means that they
typically see only the result—the production volumes—and not the high-frequency
data that may be the reason for a certain production parameter (e.g., choke
size, pressures, and temperatures).
Supervisory control and data acquisition (SCADA) is the system that connects
to the production facilities’ controllers and data sources and collects the
measured data and stores them in a database. Operators on the platform have
direct access to these data and use this information to control the wells and
the process equipment. If the engineers see these data at all, they usually get
them through a Web-browser interface and in a format they cannot directly use
for their analysis.
This paper will introduce a new concept of integrating high-frequency
real-time data to the oil company’s business office, making those data
available to engineering staff and operations management, including up to the
senior management level. Each level of the organization sees as much of the
high-frequency data as it needs or wants to see. The engineers and management
have exactly the same view as the operators at the platform and at the same
time. This might seem to be a problem at first, but in the long term, it is an
empowerment of the operators and brings engineers and operators closer together
by working as a team to manage the wells. The data also allow management to
monitor the oil and gas production leaving the platform to see if the target
business plan volumes are reached or if a well is shut in.
This paper will give insights on how the access to high-frequency data
changed the way of doing the daily work and how it changed the way operators
work together with engineers. (Note: All values in the figures within this
paper are manipulated and do not necessarily represent reality).
Horizontal wells and 4D seismic have been the last major technological
advances that the upstream petroleum industry. Now, it appears as the so-called
“intelligent field” (also named Smart Field, e-Field, and i-Field) will be the
next major technological advance in the industry. But how is an intelligent
field defined? Phrases such as “closed loop” and “self-controlled” can be read
in different publications. This is not what we will focus on in this paper,
because closed-loop control still has a long way to go before it becomes
reality. We will focus on the basics for an intelligent field, starting with
the following questions:
1. What are the main problems?
2.What has to be done on the data-management side?
3.How can high-frequency data add value to the asset-management process?
As the water depth of newly discovered reservoirs is getting deeper and
deeper, the costs of drilling a well have sharply increased. A deepwater well
can typically cost U.S. $15 to $50 million. The facility to support these wells
may cost an additional U.S. $200 to $1,000 million. These costs have
necessitated a higher level of well-performance monitoring to protect these
investments. The wells and the platform are equipped with a variety of
different sensors, measuring the performance of the wells and the platform’s
process trains with seconds-to-minute increments.
© 2006. Society of Petroleum Engineers
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- Original manuscript received:
3 June 2005
- Revised manuscript received:
23 March 2006
- Manuscript approved:
13 April 2006
- Version of record:
20 June 2006