Field Surveillance and Well-Services Management in a Large Mature Onshore Field

Abstract

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 99949, "Real-Time Field Surveillance and Well-Services Management in a Large Mature Onshore Field: Case Study," by L. Ormerod, SPE, Weatherford; H. Sardoff, SPE, J. Wilkinson, SPE, and B. Erlendson, Chevron; and B. Cox and G. Stephenson, SPE, Weatherford, prepared for the 2006 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 11–13 April. A real-time field-surveillance and well-services management system was deployed in an onshore mature field in California. The challenges of data management included automatic handling of very large quantities of real-time data, management of inventory, and integration of field-level data with corporate-level data. Technologies required for this project included software systems and integration of these with remote intelligent-field sensors and data-transmission systems. This project established that integrated intelligent remote devices, communications networks, and workflow-management software could be deployed successfully on large mature fields. Prior State of the Business Chevron's San Joaquin Valley Business Unit (SJVBU) is in the southern San Joaquin Valley in central California. The SJVBU operations encompass assets in seven oil fields, which before the merger of Chevron and Texaco were operated by those two companies. The earliest of these oil fields was developed in the early 1900s. Most of the development occurred in the 1960s and 1970s with the implementation of steamflood technology. Aggregate production from the SJVBU assets is approximately 200,000 BOPD. Approximately 15,000 active wells produce in the SJVBU, yielding an average production of approximately 13 BOPD/well. The SJVBU fields 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 is approximately 50 cp. Reservoir depth of approximately 1,000 ft enables extremely rapid drilling. Oil-production revenue is more than 95% of total sales, and virtually all wells use sucker-rod pumps (SRPs). The key operational focus of these fields concerns the challenge of maintaining this very large number of wells at optimum production. An online system for well surveillance and well-services management was installed in the SJVBU, and the experience of implementing this system was used 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 ‘n’ puff cyclic-steam wells that flow after the steam cycle, adding another 24,000 BOPD, for a total field production of 40,000 BOPD. Automation History In the 1980s, a program to increase production in the Lost Hills field was based on finding the best method to fracture the wells. Field production rose from less than 3,000 BOPD to more than 20,000 BOPD. Managing this new production became a priority, and pump-off controllers (POCs) were installed throughout the field similar to that shown in Fig. 1.