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.
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.
Where well rates are outside the range of the test separator, operators usually have no choice but to estimate well production using back allocation techniques, which rarely capture the variance in flow rate over time. This was the case of a well in the Thistle field in the UK sector of the North Sea, where high-frequency flow rate was accurately calculated using ESP real-time data, which was instrumental in measuring inflow properties. 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, which provides a linear equation that can be resolved for rate. Water cut (WC) was calculated by measuring the production tubing differential pressure (DP), which provides the average fluid density, which is subsequently converted to a WC. Analytical equations are used throughout the process, ensuring that the physics are respected at all times. This yields greater repeatability and confidence than analogous methods, which are based on correlations and artificial intelligence. The calculations provided continuous liquid flow-rate and WC trends over the 6-month life of the ESP with a frequency of one calculation per minute with excellent repeatability and resolution. This enabled us to calculate inflow properties such as productivity index (PI) and skin, as well as history matching a reservoir simulation of the drainage area. This was essential to explaining why production dropped from 1500 to 500 B/D over a period of 8 months, which was found to be a lack of pressure support. The fall in production also caused production instability because of severe slugging, which could be remediated by concurrently increasing the tubing head pressure and ESP frequency without changing the drawdown. In addition to demonstrating the superiority of an analytical virtual flowmeter over correlations or artificial intelligence, the method also shows how the model can be calibrated accurately using an alternative pump reference curve, which is independent of flow rate, as opposed to traditional centrifugal pump curves. Flow-rate independence was indispensable because of the inability to physically measure rates with the existing test separator and was key to delivering accurate results.
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.
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