From completion to production monitoring, tubing and casing pressures can provide important information about well safety and performance. Flowback of horizontal wells that have been hydraulically stimulated is particularly important to monitor. In addition, tracking these parameters over time helps the operator understand the performance throughout the life of the well. One company uses high- and low-level alarms to avoid an overpressure event and alert users of unusual well behavior.
Traditionally, dial gauges are used to measure wellhead pressures. Even today, dial gauges are regularly incorporated into wellhead monitoring schemes as reliable and inexpensive local displays. Using this technology, pumpers regularly check these gauges on their rounds. They might record readings, particularly if the well was having trouble. This manual monitoring method is simple and, for the most part, reliable. However, the challenge with all manual monitoring systems is two-fold: latency and cost. The manual system is dependent on the daily rounds of a skilled worker. If the well state changes five minutes after the pumper leaves the site, a problem could go undetected for another 24 hours or more. At best, that means lost production.
While latency can hinder well performance, the real problem is the hidden issue of cost. While dial pressure gauges are inexpensive and appeal to the cost-conscious, they often provide false economy. The common refrain among operators when asked about tubing and casing monitoring is "I have my pumper check them on his rounds." The cost of a pumper, with truck and tools, can easily exceed $100,000 annually. Even if an operation takes just a few minutes per day to manually check and record tubing and casing pressures, hidden costs can add up. The alternative to manual pressure monitoring is to install a remote monitoring system. End users should understand several important design considerations.
Remote monitoring requires some form of digital pressure transmitter. At the high end, full feature transmitters offer accuracies on the order of +/- 0.05 percent, low drift, integrated displays and multiple connections. Lower-cost options include cartridge sensors, which consist of sensing elements with basic electronics and analog interfaces. These devices have accuracies and drift specifications that can be similar to more fully featured transmitters. Standard interfaces for both types are 1-5 volts (V) and 4-20 milliamps (mA), while more sophisticated transmitters also offer digital interfaces including Highway Addressable Remote Transducer (HART) and Modbus. Both are bus architectures, meaning that multiple devices can be connected to a single pair of wires.
Wired vs. Wireless
Once a set of transmitters is chosen, they need to be connected to a local remote terminal unit (RTU) and/or a data backhaul system. Systems can be run with wire or wirelessly. Running wire between the wellhead and an RTU has been the traditional way to make a connection. Wiring is a mature and reliable method that is well understood by any worker who commonly works with transmitters.
Since wellheads are typically located in a Class 1 Division 1 zone, wiring will either require a seal (if an explosion-proof method of protection is used) or a barrier outside the zone if the protection method is to be intrinsically safe. In either case, trenching will likely be required since heavy equipment is often brought to the wellhead. Wiring costs can vary greatly depending on a number of factors. For complex installations, the true cost of wiring can be $10 to $20 per foot when all the costs are added.
During the last 5 to 10 years, wireless sensor networks have become increasingly popular in oil and gas fields and are being adopted to do tubing and casing pressure monitoring. While still not as prevalent as wired systems, they offer a different way to connect with unique advantages and disadvantages. For many scenarios, the installation is far less expensive and much faster than wiring. The wellhead can sometimes be half a mile or more away from the RTU.
One company uses long-range mesh networking radios to gather tubing and casing pressure data, often from several wells that feed a common tank battery. Without this technology, many users could not monitor this valuable data because the cost of conduit and wire would be prohibitive. In addition, wireless systems offer a unique benefit during workovers. Wireless sensors can be easily removed and reinstalled without having to install new seals and conduit.
Multiple vendors offer different wireless product configurations. Principal differences are radio frequency choice, open or closed architectures, and power source.
For example, systems used in upstream applications typically use publicly available radio frequencies called the industrial, scientific and medical (ISM) bands. The most common in the Americas are 2.4 gigahertz (GHz) and 915 megahertz (MHz). While 2.4 GHz is a global standard, 915 MHz is a standard in the Americas, offering greater transmit power and range capability. The 2.4 GHz ranges are typically measured in tens of yards to a few hundred yards, depending on obstructions. The 915 MHz system ranges are typically measured in hundreds to thousands of yards or more. Range limitations can be mitigated by meshing technologies where data can move from device to device on its way to its ultimate destination.
Architecture choices fall into two categories. Either sensors are bundled with the wireless system, or the wireless system can connect to the user's preferred transmitter. This choice also affects whether the wireless network is open to solutions from multiple vendors or not.
The final issue is power. A truly wireless radio system must be able to power itself and the attached sensor while meeting the requirements of safe operation in a hazardous area. All the commercial systems on the market today use lithium batteries, which are typically rated as intrinsically safe. Typical battery life for tubing and casing applications is measured in years. Some vendors also have intrinsically safe solar/battery systems for longer life or more challenging applications.
Using the Data
The ultimate purpose of gathering data is for decision-making. Key implementation decisions relate to how and where data will be analyzed and what actions will be taken. One of the most important design decisions is determining how much local control is executed on-site at the RTU. This can vary from none to virtually all well logic occurring at the site. Actions can include shutting in the well or otherwise controlling assets on the ground based on wellhead pressures or other data (e.g. tank levels) that is processed locally in the RTU or remotely.
Users also must determine if and how the data will be taken out of the oilfield and where it will be stored. Backhaul solutions can be private radio networks, satellite modems, cellular networks or land lines. Remote monitoring systems collect and store data and permit the user to view and analyze long-term performance trends. Some organizations have their own dedicated data historians for analysis. In either case, the goal is to permit the user to analyze long-term performance trends that will allow the enterprise to operate the field safely and to optimize production. A remote monitoring system may also provide alarms that help prevent spills and prevent equipment failure or damage.
There are no one-size-fits-all solutions in the oilfield or for remote monitoring. While there are common building blocks, a system that monitors tubing and casing pressures is part of an overall remote monitoring solution.