Summary
This paper describes the planning for, implementation of and results
generated by a real-time field surveillance and well services management
system, as it was deployed in an onshore mature field in California, USA. The
motivation behind the deployment of this system was simultaneously to improve
efficiency and reduce operating costs in this large field with over 1,000
wells.
The paper will describe how the business processes and supporting work flows
were defined. This is an essential step before any technology can be deployed.
The challenges of data management included not only the automatic handling of
very large quantities of real-time data, but also the management of inventory
and the integration of field level data with corporate level data. Historical
data had to be brought into, and made compatible with the new system. The
technologies required for this project included the software systems and the
integration of these with remote intelligent field sensors and data
transmission systems.
The impact of the system has been material to the performance of the asset.
Examples will be given of tangible improvements in performance across the
disciplines of surveillance, production engineering, and well services. One
critical factor to the successful deployment of this system includes the
organizational changes needed to support the new working practices enabled by
the system. The paper will discuss the required change management programs.
The success of this project has clearly established that a "smart"
solution integrating intelligent remote devices, communications networks and
workflow management software can be successfully deployed on large, mature
fields. The deployment process to achieve this has been assimilated and is now
being reproduced in many other similar fields across North America. The paper
will indicate some of the areas where this combination of technology and
supporting change management will be expanded in the future.
Introduction
This paper describes the evolution of an oilfield automation and software
system that has now reached an innovative level of surveillance and work
planning. The historical automation level was at that of individual wells. (It
is estimated that approximately 10% of the world’s wells are automated to this
degree.) Next, this data was brought to field offices allowing remote
surveillance. (Most automated wells have some similar type of data
consolidation.) The next step was to feed this data automatically into
engineering models, which is rarely done (other than with much human
intervention).
To build upon this relatively high level of historical automation and
surveillance, the decision was made to go a step further and introduce a highly
innovative software system that not only further developed the remote
surveillance concept, but also managed the well services activities so that
full well histories would be electronically managed. What was particularly
novel was the concept that the workflow processes themselves would be defined
in, and managed by, the software. There are few instances of this level of
business process automation being applied in the upstream operations and
engineering sectors, and the lessons learned are valuable.
Prior State of the Business
Introduction to the Business. Chevron’s San Joaquin Valley Business Unit
(SJVBU) is located in the southern San Joaquin Valley in central California.
The SJVBU is headquartered in Bakersfield, California, which lies in close
proximity to the fields operated by the business unit (BU). The SJVBU
operations encompass assets in seven individual oilfields; before the merger of
Chevron and Texaco, these assets were operated individually by the two
companies. These assets are comprised of the Coalinga, Cymric, Kern River, Lost
Hills, Midway Sunset, McKittrick, and San Ardo fields.
The earliest oil fields in the San Joaquin Valley were developed from the
early 1900s with the majority of the area’s development taking place in the
1960s and 1970s as a result of steam flooding technology. Chevron’s aggregate
operated production from its SJVBU assets is approximately 200,000 BOPD. There
are approximately 15,000 active producing wells in the BU yielding an average
production of approximately 13 BOPD per well.
The SJVBU fields, largely produce from relatively shallow reservoirs,
including the Miocene-Pliocene, Kern River, Tulare, Temblor, and Potter
formations, which typically have porosities ranging from 20 to 30% and
permeability in the range of 1 to 5 mD. Oil gravity ranges from 13 to 20 API
and viscosity approximately 50 cP. The reservoir depth is typically only about
1,000 ft making wells extremely rapid to drill. The production revenue from oil
is more than 95% of total sales, and virtually all wells are lifted by sucker
rod pumps (SRPs).
The key operational focus in the production management of these fields
involves the challenge of maintaining this very large number of wells at an
optimal production level.
This paper discusses the introduction of an online system for well
surveillance and well services management in SJVBU, and in particular, with the
experience of implementing this system in the Cymric field. Cymric is typical
of the SJVBU fields and contains approximately 800 SRP wells producing 16,000
BOPD. Cymric has another 500 “Huff and Puff” cyclic steam wells that flow after
the steam cycle, adding another 24,000 BOPD, for a total field production of
40,000 BOPD.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
20 January 2006
- Meeting paper published:
11 April 2006
- Revised manuscript received:
25 May 2007
- Manuscript approved:
28 June 2007
- Version of record:
20 November 2007
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