As technology and well count advances, the sheer volume of data being generated is growing at an unprecedented rate. Close analysis of problem wells becomes difficult, and with streams of data arriving over data transmission systems, operator workload has increased dramatically. The ability to manage reservoirs on a well-by-well basis can become compromised. Under pressure, resources can become stretched due to the high demands on the increasing numbers of wells.
Well surveillance
In response to increased need for intervention, Zenith developed the Z-Sight automated well surveillance system to improve production rates. The system takes the hard work out of well surveillance by automating the process of data analysis and optimization, recently increasing oil production in one South American well by 39% and generating an additional US $45,900 revenue per day.
A single well lifted by an electrical submersible pump (ESP) can have 20 or more key data streams associated with its operation that can be updating more than once per minute, resulting in potential overload.
The operator traditionally needs to perform well tests and further calculations by launching the data into performance software to gain a full understanding of how the well is performing.
The Z-Sight system provides real-time recommendations on how best to operate the well to achieve optimum production within the limitations of the lifting equipment. A comprehensive model of the well and lifting equipment is referenced in real time against measured data points from surface and downhole pressure and temperature devices.
Intelligent algorithms judge whether the pumping system is running within a desirable operating condition, and the technology performs real-time sensitivity studies to assess whether production can be improved.
Instead of raw data streams, the operator is presented with a suggested wellhead pressure or operating frequency and the potential production gain associated with the new operating point that is within the capability of the well and equipment performance.
Well information is presented in a simple dashboard dial system available at any location within the operator's facilities, including the well site. This allows the team to work on a well in real time while retaining full control of the operation, bringing logistical cost saving implications.
Historically, the process for optimizing an artificial lift well could take days or weeks. Now operators can instantly recognize and prioritize wells requiring attention and cut this turnaround time to hours.
Simple "well status" operating philosophy filters out unnecessary operator analysis, with all processing performed at the well site enabling true real-time analysis. Key data points that might not be measured in real time such as water cut, flow rate, and bottomhole flowing pressure are all calculated automatically using the comprehensive software model, which can be calibrated against any well test data available.
Optimum production
The latest feature to be added is field-wide management. When deployed field-wide, the system can be used to quickly obtain the optimum balance of production from the reservoir to maximize recovery and minimize water cut. Bottomhole flowing pressure or flow rate targets are chosen by the company reservoir engineers for each well to achieve the overall drawdown on the reservoir. The system uses these targets to automatically recommend the correct operating point for each individual lift system in real time. As reservoir or flowline conditions change or targets are adjusted, the system will automatically compensate the operating points in real time, well by well, to ensure the desired method for producing the reservoir is achieved.
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Remote access through a secure Internet connection facilitates surveillance and control of the lifting equipment from anywhere with a standard web browser. Secure log-in presents the operator with a field map of the wells, each with a status flag. The status flag indicates a well is not producing, has a pump or well problem that requires attention, has potential for optimization with a recommendation on potential gains, or is running optimally and requires no further attention.
The operator can instantly recognize and prioritize wells requiring attention, make informed decisions, and access the decisions quickly using the remote control function to start, stop, or change operation of the well.
By having remote access and control, operators have complete control of their operations in an instant. They are immediately notified by email or SMS when a well shuts down and production is lost. The operator then has the ability to resume production immediately through secure remote control of the ESP drive.
Impact on an already optimized well
In one case study, the production of a well was previously thought to be fully optimized to the limits of the ESP. The well was producing around 940 barrels of fluid per day (bf/d). After installation of the real-time system, the automated analysis showed that the well was not achieving the target bottomhole flowing pressure but was close to the upper range limit of the ESP while running at 55 Hz.
The real-time system predicted through automated sensitivity studies that the frequency could be increased to 61.9 Hz while keeping the ESP within its operational limits. The automated sensitivity calculations recommended an additional 123 bf/d was achievable by increasing
frequency to 61.9 Hz. The frequency was subsequently increased manually from 55 Hz to 56 Hz and then by remote control to 61 Hz. Adjustment was performed in
1-Hz increments to verify the system's recommendations and enable independent well tests to verify the results. The real-time system calculations for flow and water cut were verified independently by well test during the optimization process.
Boosting the frequency resulted in oil production increasing by more than 71 b/d.
Impact on an underperforming and undersized ESP
On another well, the automated ESP diagnosis highlighted that the ESP was underperforming by 30%. The system recommended that the ESP frequency could be safely increased from 42 Hz to 46.7 Hz. The system automatically showed that 46.7 Hz was still not sufficient to achieve the target drawdown because further increases of frequency were limited by the ESP pump range.
The bottomhole flowing pressure stabilized at 1,267 psi. The target bottomhole flowing pressure for the well was 1,131 psi, providing scope for an additional 1,142 barrels of fluid. The ESP installed was not capable of providing this additional flow rate, so it was resized based on the recommendations of the real-time system. Drawdown was optimized to the target bottomhole flowing pressure, and the flow rate was increased.
An automated diagnosis and frequency optimization of the underperforming ESP provided an average additional 200 b/d ($6.7 million) in the 334 days of operation with the real-time system.The ESP underperformance issue was highlighted as soon as the automated system was implemented on the well. Further increase in rate was limited by the upper flow range of the ESP. Resizing of the ESP in January 2012 resulted in an additional 455 b/d of production ($49,500/day).
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