The Western Desert in Egypt has multiple fields in which most wells are artificially lifted. Wells with ESPs represent the major percentage of oil production by volume in that area. ESP run life is a principal criteria that is typically evaluated before the initial design and throughout the well's life time. Most wells are remotely positioned from one another and from the main gathering stations (2 to 8 Km. approximately). This is one of the major challenges when trying to maximize uptime and reduce the production deferment. Operational issues including power supply and capacity limitations as well as changing inflow conditions can have negative impact on the ESP run-life, predominantly caused by excessive trips and shutdowns. Also such trips will result in lengthy downtimes due to the remoteness of the wells. On the production side, these trips will ultimately have a major effect on production targets due to intermittent deferment. ESP wells connected to real-time monitoring and surveillance systems incur less lifting costs because of proactive responses and early detection of incidents. Systematic alarms along with pro-active remedial actions can minimize such preventable trips while maintaining the integrity of the ESP, eventually extending its run life. This paper discusses a number of case studies showing how the implementation of such system prevented trips in some situations and allowed making key decisions and recommending remedial actions to optimize the ESP operation.
Electrical submersible pumps (ESPs), one of the main artificial lift methods employed in the Western Desert of Egypt, can significantly influence the operating costs associated with producing assets. ESP well interventions are typically complex and costlier than other artificial lift-related workovers. Consequently, it is important that operators develop a strategy to closely monitor ESP-lifted producing wells to maximize production potential, ESP efficiency, and run-life. This case study reviews the experience gained from developing a monitoring program and response strategy to optimize ESP well value in Egypt. Qarun Petroleum Company (QPC), one of the main operators in the Western Desert of Egypt, operates more than 340 ESP producing wells. Similar to other ESP operators in the area, QPC deals with a range of challenges that can affect ESP performance, run-life, and ESP uptime. To address these challenges, a number of wells were selected for a monitoring program based on the transmission of downhole sensor and surface data. The program called for dedicated surveillance engineers to analyze and review the data in real time to identify any suspicious events that may pose a risk to the ESP's performance. Furthermore, a robust communication workflow was developed to enable the surveillance engineers, field operators, and production engineers to communicate, identify root causes of the captured events, and take corrective actions in a timely manner. Actions could then be executed remotely, eliminating health, safety, and environment risks and reducing the time required to optimize the performance of the ESP wells. The surveillance system proved to be valuable in several instances. Events that could have drastically affect production, such as motor overheating and gas interference were detected in real time. Flow recirculation was also identified more rapidly than without the system; thus, improving operational responsiveness and reducing deferred production. In addition, an ESP failure was avoided by optimizing the pump speed automatically to avoid gas-locking effects without compromising production. This study showed that production gains up to 9,000 BOPD were possible. Moreover, significant improvements in ESP run-life was observed in the monitored wells when compared with premonitoring performance. Field case studies are used in this study to demonstrate the well production and operating expenditure improvements resulting from real-time surveillance and continuous performance monitoring for ESP wells and fields.
To arrest production decline without infill drilling, one must maximize production from existing wells, typically by identifying wells with skin and increasing drawdowns on wells with good pressure support or lower water cut. This paper examines how high-frequency, high-resolution flow rate measurements on ESP wells can identify such opportunities without the need for buildups which cause production deferment. The application of this workflow was examined for wells in Egypt. To obtain flow rate measurements at frequencies greater than once an hour, without dedicating a test separator or multiphase flowmeter to each well, the method relied on real-time data to calculate liquid rate and water cut. The liquid flow rate calculation was based on the principle that the power absorbed by the pump is equal to that generated by the motor. Water cut was calculated by modelling the production tubing as a gradiometer. Analytical equations ensured that the physics were respected at all times, which yields greater repeatability and resolution than analogous methods based on correlations and artificial intelligence. The well analysis in Egypt demonstrated that the evolution of depletion and skin could be identified qualitatively using plots of rate-normalized differential pressure. These diagnostic plots are only possible with high-frequency and high-resolution flow rate measurements and could not be generated using traditional monthly production test data. The case studies also illustrated how frequency and resolution enabled real-time measurement of the impact of small changes in pump speed on both the reservoir inflow characteristic as well as production. This qualitative technique makes it possible to fine-tune production iteratively without the need for time-consuming simulation, which was nevertheless also conducted to quantify the changes in reservoir pressure and skin on the wells considered in this case study. Furthermore, with a water cut resolution of less than 1%, potential water coning can be identified rapidly, which allows the production operator to test small drawdown increases. Finally, this method also has the advantage that it can reduce the mobilization of testing equipment to the well site to measure the change in production, thereby minimizing and eliminating health, safety and environment (HSE) risks in remote locations while also optimizing the use of the available test packages. This novel use of real-time gauge data demonstrates how a cost-effective method can improve well testing quality and thereby identify production optimization opportunities, providing the means to arrest decline. This case study provided a proof of concept on specific wells, however fieldwide application is necessary to identify the wells with the highest production optimization potential because, typically, most of the gain is obtained from a minority of the wells in a given field.
Managing a waterflooding project always has its sets of challenges and associated costs. The use of advanced completions can aid in minimizing such costs, while increasing the field recovery. This study highlights the deployment of an advanced completion in a waterflooding project in a newly developed field located in the Egyptian Western Desert. Initially, a specific area of the field started to experience a decline in reservoir pressure. The operator decided to drill a new injection well to provide the required pressure support in this area. Unfortunately, the amount of water produced by the field wells was not sufficient to feed an additional injection well. Several solutions were explored to tackle this issue. The most straightforward, but costly, solution was to drill a new water source well. Another proposed method was to rely on a natural dump flood, by perforating both the injection and production zones within the same wellbore. The pressure difference should create a "natural injection" effect. However, the study showed that this method would not provide the required injection rate. Finally, a novel solution was selected to provide the required injection rate with the aid of an advanced completion. The flow was assisted with an electrical submersible pump (ESP) to control the injection rate. The pressure support was successfully provided by producing water from the producing zone to be reinjected into the target injection zone, all within the same wellbore. The effectiveness of the solution was confirmed with the aid of a real-time monitoring and surveillance system. Later, this aided in optimizing the production of other nearby wells.
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