This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately 40% of the oil production is from the ESP oil wells.
To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields.
The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 11 horizontal producers are on ESP lift and the remaining three wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities.
The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and SRB. 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field.
Understanding the integrated performance of complex artificially lifted wells on not normally manned (NNM), offshore platforms without invasive techniques represents a challenge not only to minimizing operating costs but also to optimizing production and thereby maximizing value. Often the analysis of such problems is hindered by the complex interactions between identified production constraints and by a lack of operating data.
The Cliff Head oil field (offshore Western Australia) is developed with an innovative coiled-tubing deployed-electrical-submersible-pump (CT-ESP) artificial-lift system. This paper describes the process by which ESP and well data, in conjunction with a well-performance-modeling software, have been used as a powerful tool to diagnose well-performance issues and optimize production. Production trends were created on the basis of real-time production data to understand ESP performance. Individual-well models were created to identify potential causes of declining performance--in this case, the use of an ESP performance-limiting factor (PLF) indicating deteriorating ESP performance because of solids buildup.
On the basis of the model results, chemical soaks were implemented on two production wells to remove flow restrictions within and around the ESPs. The treatments increased the oil-production rates by 17 to 48%.
Following a debottlenecking study, reservoir simulation in combination with detailed ESP-performance analysis concluded that total-field-production improvements of up to 50% were possible. Consequently, the next phase of field development will install larger-capacity ESPs.
This paper outlines how field data and desktop tools were combined successfully to monitor and diagnose well-performance issues to deliver material production enhancements.