This paper explains the development and implementation in the Schlumberger artificial lift real-time surveillance center of a workflow to track ESP alarms from their initial identification through their classification to the analysis of their root-cause. The workflow uses a QHSE database with Web access to enable collaboration between the surveillance center and field locations throughout Europe and Africa. Of more than 700 alarms which were substantiated over an 18month period, over one third were classified as "critical", i.e. if no actions were taken, an Electric Submersible Pump (ESP) failure could potentially ensue. As such, real-time surveillance was seen to contribute to an increase in ESP run life, firstly, by preventing the ESP from being misoperated and experiencing excessive stress, and secondly, by using the alarm classification as the basis for service quality reviews to promptly identify remedial action items.
In the Republic of Congo, the reservoir pressures in the Likalala and Kombi fields have decreased since production start-up and have dropped below the bubblepoint resulting in secondary gas caps. Consequently, the producing gas/oil ratio (GOR) and gas void fractions (GVFs) of the wells have increased. These fields are produced using electrical submersible pumps (ESPs); however, the drawdown has been limited by traditional ESP gas handling technology, which typically cannot handle GVFs higher than 40%. Total E&P Congo installed three ESPs with advanced helicoaxial pump technology in these two reservoirs. After nearly 2 years of operations on wells Likalala 106 and Kombi 102, production has stabilized and increased as a result of eliminating shutdowns and increasing drawdown. On the third well, Likalala 112, helicoaxial technology ensured that production targets were achieved despite unexpected high GOR and GVFs. This paper reviews these applications, focusing on the ESP and well outflow simulations, which demonstrate that the higher GVF handling capability of the pumps provides the technology needed to increase drawdowns. The paper includes analysis and review of well performance, from inflow through to facilities. It also reviews the in-situ GVF performance of the gas handling device with GVFs measurements as high as 80%. A head correction correlation is also matched to the field results providing users with a method for modeling future ESP applications with high GVF. Finally the downhole gas separator efficiency is reviewed and suggestions made on how future completions can achieve higher separation efficiencies. The results are used to provide a benchmark and design guidelines for future high GOR-ESP applications.
Routine testing of wells with electric submersible pumps (ESPs) is usually conducted monthly to monitor liquid rates, water cut (WC), and gas/oil ratio (GOR). This monthly testing is the most common form of production and reservoir surveillance and is implemented in even the most mature fields where cost control generally takes precedence over reservoir surveillance. However, this technique has its limitations. The most common limitation is insufficient testing duration to capture a representative sample of reservoir fluids. This testing duration issue is often the case in low-flow rate and deep wells, which require several time-consuming whole or complete liquid holdup periods. Other potential problems include insufficient resolution or repeatability to identify trends in liquid and water-cut rates over short periods of time. To date, the only method for resolving these issues has been to install permanent multiphase meters on each well. Although this method has been implemented in some fields, it is uneconomical for most wells. An analytical method is described for a flow rate calculation that can be implemented in wells produced with ESPs and equipped with downhole gauges and real-time monitoring systems. These downhole gauges and real-time monitoring system provide continuous real-time virtual flow rate measurements and therefore, both liquid and water-cut trends, which deliver the required resolution and repeatability to support both well performance diagnostics and near-wellbore reservoir analysis. This technique, which has the advantage of being valid for both transient and steady-state conditions, provides instantaneous flow rate data when used with real-time data. Case studies presented will illustrate model calibration and its application to back allocation and transient analysis. Examples are provided to show how the data can be used to rapidly identify changes in productivity index and reservoir pressure across the drainage area; thereby, enabling real-time production optimization.
Due to increased hydrocarbon demand and technological advances, production from heavy oil fields in the United Kingdom Continental Shelf (UKCS) has become possible over the past 10 years. Despite substantial reserves in the UKCS with crudes less than 20° API, most of the activity has been confined to exploration and appraisal drilling. The main reason for the restricted activity has been the high uncertainty of the reservoir and fluid properties. Operational complexities inherent to heavy oil also limit the use of conventional appraisal-well testing technology.A method was developed to determine the most suitable technology for testing wells with heavy oil using an electrical submersible pump (ESP). The solution was applied in the Bentley field located in the UK sector of the North Sea in block 9/3b, on which final appraisal well 9/3b-6Z was flow tested in December 2010.The technical challenges included a short weather window, maintaining fluid mobility through the surface-testing equipment, oil and gas separation for metering, obtaining accurate flow measurements, and designing the most appropriate ESP system. A combination of technologies-dual-energy gamma ray venturi multiphase flowmeter, real-time monitoring, and a novel ESP completion-provided a solution that enabled successful well test execution. A multirate test reaching a final stabilized rate of 2900 bpd, with a subsequent period of pressure buildup was accomplished in less than 2.5 days with 10 to 12° API crude. A key lesson was how to obtain the quality of data that would enable reservoir engineers to extract with confidence a productivity index and perform pressure transient analysis for reservoir characterization. This success paves the way for development drilling to commence on the Bentley field at the end of 2011, but also demonstrates potential that can enable new heavy oil field developments.
Installing ESPs in a reservoir for the first time is always fraught with the uncertainty of achieving economic run lives and this is further amplified in harsh conditions. To mitigate the financial and production risks, sufficient production gains are required to overcome potential short ESP run lives. This paper discusses the results of four pilot ESP wells in Algeria and how infant mortality was eliminated in addition to achieving early production gains. Key to achieving the production gains was candidate selection and well testing to confirm the well productivity and aquifer pressure support. This process also mitigated risk by selecting wells from a reservoir sector with a historical low incidence of asphaltenes and GORs, which have not spiked substantially above solution GOR. Once the ESPs were installed, the production gains were achieved by correctly managing drawdown through real time surveillance, which was also used to manage the stress on the ESP and avoid infant mortality. Longer term run lives was achieved by selecting the correct ESP materials and completion architecture for the well conditions. At the time of writing this paper, none of the four ESPs had failed. The most recent installation had been running for 400 days and the oldest for over 1,300days, which is no small feat when one considers the harsh conditions; a reservoir depth of 10,500 ft TVD with a bottom hole temperature of 245 deg F and a volatile hydrocarbon (41 deg API) with a high GOR. This is compounded by an aquifer with water densities as high as 1.25 due to high salt content, which causes both corrosion and halite scale to form on a regular basis, which was treated with fresh water injection. In two of these wells, net oil production was doubled, but more importantly the recovery factor was substantially increased as the higher ESP drawdown mobilised reserves which would not have been produced with gas lift. Finally, the injection gas saved from converting two wells to ESP was sufficient to complete 4 to 5 new wells with gas lift completions. In terms of technology, the main innovation was the use of an ESP digital twin to monitor ESP health in real time, which was particularly useful in managing the transients associated with slugging. An equally noteworthy take-away was how a holistic approach, which integrated reservoir, completions and production engineering provided seamless management from project definition all the way through to execution.
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