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.
The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011.
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
Neber, Alexander (Schlumberger) | Cox, Stephanie (Schlumberger) | Levy, Tom (Schlumberger) | Schenk, Oliver (Schlumberger) | Tessen, Nicky (Schlumberger) | Wygrala, Bjorn (Schlumberger) | Bryant, Ian David (Schlumberger)
New tools are now available to provide a rigorous and systematic play-based exploration approach to the evaluation of unconventional resources. Coupled with petroleum system modeling, this methodology offers an efficient and effective approach to identify "sweet spots?? early in the life of resource plays. Petroleum system modeling can be applied to predict the type and quantity of hydrocarbon in shale formations, as well as the proportion of adsorbed gas and geomechanical properties that are important for hydraulic fracture stimulation of shale reservoirs. Maps of these properties are then converted to chance-of-success maps for hydrocarbon generation, retention, and pore volume that can be integrated with nongeological factors, such as access and drilling depth required to reach target reservoirs. These play-based maps are expressed in probability units, so simple map multiplication provides a map of the play's overall chance of success, delineating the sweet spots. A similar methodology is applicable to evaluation of coalbed methane resources.
In this paper, we illustrate this methodology using examples from shale oil and gas shale plays in North America. These include data-rich plays from the North Slope of Alaska and data-poor plays from the northeastern and southern regions of the United States, which are more representative of many Asia-Pacific basins. We show how predictions from petroleum system modeling based on sparse data provide a good match with results of subsequent development drilling and production.
Petroleum system-based assessment of resources in place, combined with an assessment of overall play risk, enables companies to make decisions on acquisition of acreage early in the life of unconventional resource plays based on the probability of them containing economically viable resources.
Liu, Zhen (Jiangsu University of Science and Technology) | Zhu, Renqing (Jiangsu University of Science and Technology) | Ji, Chunyan (Jiangsu University of Science and Technology) | Chen, Minglu (Jiangsu University of Science and Technology) | Teng, Bin (Dalian University of Technology) | Li, Liangbi (Jiangsu Modern Shipbuilding Technology Co. Ltd, Jiangsu University of Science and Technology)