Real-Time Field Surveillance and Well Services Management in a Large Mature Onshore Field: Case Study
- Laurence Ormerod (EPS Ltd.) | Hugh M. Sardoff (Chevron Corp.) | Joe Wilkinson (Chevron USA Inc.) | Bill Erlendson (Chevron) | Brian M. Cox (eProduction Solutions, a Weatherford Co.) | Gregory B. Stephenson (eProduction Solutions, a Weatherford Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2007
- Document Type
- Journal Paper
- 392 - 402
- 2007. Society of Petroleum Engineers
- 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 7.6.6 Artificial Intelligence, 5.6.4 Drillstem/Well Testing, 3.1.6 Gas Lift, 5.4.6 Thermal Methods, 1.6 Drilling Operations, 3.3 Well & Reservoir Surveillance and Monitoring, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 6.1.5 Human Resources, Competence and Training, 7.6.2 Data Integration, 4.2 Pipelines, Flowlines and Risers, 3.1 Artificial Lift Systems, 3.1.5 Plunger lift, 7.6.4 Data Mining, 3.1.1 Beam and related pumping techniques, 4.3.4 Scale, 4.4.2 SCADA
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- 775 since 2007
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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.
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.
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