Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
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.
Most offshore wells that require artificial lift are gas lifted, as gas typically is readily available and compared to other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electric submersible pumps (ESPs) can
efficiently and economically increase oil production and reserves recovery under the appropriate operating conditions. This may translate to a lower abandonment pressure in the long term—possibly reducing the total number of wells required to deplete an asset.
Since few ESPs currently are installed in offshore wells, an ESP screening "Rules of Thumb" was created as a simple guide for prioritizing offshore ESP candidates. The selection criteria focus on feasibility of installation, operability conditions
and operating practices to maximize run life, and economic considerations. ExxonMobil† and industry experience from North America, South America, West Africa, Asia, Australia, the Middle East, and the North Sea provided the basis for the study.
The plans for many of the upcoming deepwater projects involve the use of highpower Electrical Submersible Pump (ESP) Systems for Artificial Lift. However,the perception in the industry is that the average run-life currentlyachievable with such high power ESP Systems is much shorter than what would bedictated by robust project economics, given that intervention costs in theseapplications can be very high, in the US$50MM - 75MM range. Therefore, theconsensus among operators is that there is a need to try and improve thereliability of these systems.
In response to this industry need, DeepStar® recently commissioned a gap studytowards identifying the barriers that may be preventing ESP Systems fromachieving the desired reliability as well as the additional R&D effort thatmay be required for the industry to close the existing gap. DeeepStar® providesa forum for deepwater technology development, while leveraging the financialand technical resources of the industry (http://www.deepstar.org/).
This paper presents a summary of the results of this study, including: a) theMean Time To Failure (MTTF) that people believe is currently achievable (i.e.with current technology); b) the biggest differences about these applications,which introduce additional uncertainty to the ability of the system to performreliably; c) the main sources of uncertainty regarding each of the major ESPSystem component's reliability; and d) the tentative plan that was outlined aspart of the project, to address the gaps that were identified.
The Gap Analysis was based on phone interviews conducted with recognizedindustry experts, on discussions that took place with members of a TechnicalCommittee (TC) that was put in place for the project, and on a broader industrysurvey conducted through the internet. The proposed go-forward plan consists oftwo follow-up projects: one focused on improved system design and operationalpractices, including system monitoring (or surveillance) and control; and onefocused on validating the design of key components of concern, for thespecifics of these applications, through laboratory testing. The proposednear-future R&D effort has the support of major operators, but still needsto be fine-tuned, with input from the industry, before the actual work canproceed with buy-in and financial support from all of the partiesinvolved.
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.