TRUSSVILLE, AL.–Optimizing well performance is about to get a lot easier, thanks to advances in production automation.
Oil and gas companies long ago began deploying automation tools to gain operational insights and remotely control key production equipment. Because of automation, pumpers, engineers and operations managers know more today than they ever did before about well and equipment status, performance variables, operational history, failure risk factors, etc. Mundane tasks and predictable problems are automatically handled. Potential problems are detected or even avoided, eliminating downtime and lost revenues. Personnel are freed to focus on performance, and improvements in automation tools and interfaces will make them ever-more efficient.
That is where automation’s true value lies: in improving human performance and efficiency. Pumpers are busy people, responsible for the daily management of 60-80 wells or more. They and other field-related personnel have a vested interest in ensuring safe, efficient and high-performance operations. They have a lot to do.
Automation has already improved problem detection and avoidance, giving field personnel data, control and built-in logic. Recent innovations in multiple-stream communications, mobile phone application-like touchscreen interfaces, and standardized control systems can now deliver a step-function change in well optimization performance.
Automation’s initial value was in providing the data and controls required to better manage field equipment and producing assets. Proper well management begins with physical equipment checks and reviewing data indicating the health of each component. Pumpers ensure fluids are being pumped, tanks are at appropriate levels, equipment is operating within desired parameters, etc., and adjustments are made based on the production schedule.
With automation, sensors and transducers routinely collect a wide range of data that can be used to improve safety, equipment life, lifting costs and production. For example, in a saltwater disposal application, sensors can detect whether the fluid level is above target and communicate the need for corrective action (in this case, speeding up the pump).
Similarly, if the discharge pressure from a tank rises above the maximum preset specification, a pressure transducer can identify the problem and issue an alert to the pumper and/or automatically turn off the pump in order to protect against a pipe burst. Other problems such as leaks, rod overstress, fluid pound, and friction can also be addressed.
Simply by detecting problems early, automation reduces repair and maintenance costs, improves safety, protects the environment, extends equipment run times, and keeps production on line to keep revenues flowing. It can identify potential reservoir issues and producing wells headed for failure. It prevents manual work whenever possible and avoids bad decisions based on insufficient data.
As automation has evolved, logic has been added to automatically address common problems, the classic example of which is wells reaching pump-off conditions. Variable speed drives make it possible to run pumps at different speeds, adjusting to the inflow of fluids to avoid over pumping and fluid pound. Variable speed drives and control systems allow operators to set conditions and make appropriate adjustments before problems escalate to the point of requiring pump off, which can be a serious drain on efficiency and cause costly pump failures. In addition to enhancing operational efficiencies and reducing wear and tear on pumps, rods and tubing strings, reducing ESP stop and starts, pump-off control also results in increased production.
In the early days of automation, gains were so promising and technology was so new that system complexity was acceptable. After all, when energy costs could be cut by 10-25 percent by reducing or eliminating well pump-off conditions, it did not seem to matter that only experts could modify the controls.
Much More Approachable
Automation has become much more approachable. Recent innovations in problem detection improve how data are presented to the operator. Interfaces are moving toward a standard that makes interaction as simple as possible for the operator. With today’s high-resolution color touchscreen technology and a bit of information design, automation systems can be as easy to program and use as smartphones. (See Figure 1) That is a key objective for equipment designers and users alike.
For those problems that do not have a predefined and programmed resolution, it is imperative that field personnel know a problem exists as soon as possible. Supervisory control and data acquisition-based alerts, central dashboard displays, easy fault charts at the wellhead and remote control all play a part in helping operators quickly resolve unusual conditions or situations where equipment is operating “out of spec.” (See Figure 2)
Today’s advanced SCADA packages are designed “field ready” to perform remote monitoring, historical data acquisition, and control of all artificial lift and other oil and gas production equipment. Using cellular or satellite-based data connectivity at the well site, the technology greatly reduces SCADA infrastructure while providing secure access to well conditions and production information to monitor wells in remote locations from any Internet connection or mobile device, including smartphones.
Large amounts of production data can be trend for a single well or across an entire field with large numbers of wells, with data viewable on a scale of seconds to years. State-of-the-art solutions provide various ways for users to access and interact with data. In monitoring wells, operators can add notes to mark significant events or note changes in well equipment, control settings, etc. Notes are stored chronologically, so users can more easily understand the effects that control changes have on production. Notes are also included in trend cycles, so that any note added to the system appears in all trend reports. (See Figure 3)
SCADA also allows users to set conditional alerts on well data. When conditions in a well trigger an alarm, the system sends text and email messages. Alarms are date and time stamped, and because notes are stored in chronological order, it gives users a record of alarms, changes and the results that followed. Meantime, polling features let users instantly know how up to date data are, and how much time has elapsed since the last polling.
With common problems detected and handled through automation, field personnel are able to turn their attention to more proactive management, including problem avoidance. Experienced field personnel recognize many problems before they occur. Those that can be characterized by collected data and resolved through predefined steps are prime candidates for automation. Using a saltwater disposal tank as an example, if minimum and maximum levels are preset in addition to the target level, then the pump speed can be managed proactively rather than in reaction to an impending overflow. (See Figure 4)
Automation continues to expand its scope as field personnel provide input to new developments. This virtuous circle improves both equipment and human efficiency. At the same time, the custom-style of early systems is being replaced by engineered solutions. These packaged drive systems have standard components and application interfaces for pumpers and central office analysts alike. Color coding helps pumpers navigate the data and identify parameters that are out of spec. Touchscreens save time and reduce frustration.
The advantage of these systems over customer- and application-specific programmable logic controllers is in their standardization and interface design. Field personnel have greater flexibility and lower costs when deploying systems that they can program themselves and reprogram as needed, rather than depending on an expert technician. And because the interface provides a standard framework for display, pumpers can move from one pump to the next using the same methodology to review data.
For example, the data collected during a beam pumping operation will share some commonality with data acquired for an injection pump operation, but will also have unique elements. The framework organizes data into common collections such as faults and trends, displaying them in the same way regardless of pump type. Even if the pumper is unfamiliar with a particular drive type, the automation interface is familiar.
Once problem detection and avoidance are under control, field personnel can focus on fine-tuning performance for each and every well. Doing so requires easy access to operational data and an intuitive methodology for making changes. One of the biggest challenges is training and staff development. Technology is rapidly being simplified to remove the need for formal training. Interactions with production automation interfaces need to be as intuitive to well management personnel as a smartphone is to a younger child.
Operators need to be able to quickly determine current status at a glance. Depending on field management practices in place, this may mean that on any given day, the pumper can skip visiting some wells that are performing properly. At the least, a pumper can move from well to well efficiently, spending his time at wells that need attention. A simple, intuitive and accessible design makes it easy for the pumper to tell the difference between wells that are performing as they should and those that are underperforming.
Recent developments in production automation make performance-related decisions faster by presenting key information in a way that is both intuitive and fast to process. Optimized interfaces group key data such as trend and fault charts and provide shortcuts to them. To fine-tune well performance, the pumper needs charts of pump off. To create a schedule of proactive maintenance, the pumper needs a history of levels and faults.
Most important, the pumper must always be presented with actionable data; information that supports decisions. Pumpers given the authority can set parameters and make changes at the wellhead. While engineers and pumpers may not agree, the system gives them both all the data on which to base a decision.
Similarly, well data must be easily available for remote monitoring. New systems are enabling multiple simultaneous SCADA sessions, which reflect the reality that companies often have multiple systems for monitoring and alerts.
Well performance management looks for the reason behind underproduction. It makes small changes to decrease fluid level fluctuations and optimize pump speed to gain a few percentage points of improvement. It recognizes that reservoirs change over time, and therefore, must be continuously monitored and tweaked. Optimizing performance for each well improves overall production. Lifting costs will go down while reliability goes up. It is the kind of work that can only be done with extra time that is found in the day, which is something that automation provides.
Maximizing well performance is a demanding job. To some degree, the pumper is always on duty, because wells run 24 hours a day, seven days a week. Automation helps the pumper be more efficient. One of their big challenges is getting access to all the information needed to determine the root cause of inefficiency. Supporting informed and rapid decision making is a key goal of automation. This is fundamental to keeping wells consistently pumping, production optimal, equipment available and costs at a minimum. It is what leverages human capital.
Article is from The American Oil & Gas Reporter: August 2013 | Field Processing and Automation.
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