Data, control requirements drive need for modular, scalable control architecture.
Drilling advancements have spurred the evolution of oil and gas operations from simplistic single-well pad fields to more complex multi-well pads.
Today, many producers are using fracking and lateral drilling techniques to place 10 or more wells on one pad. Some operators are even pushing their operations to as many as 52 wells on a single pad.
These advancements have not only increased production recoveries from wells but also created entirely new production opportunities in unconventional areas. They also have enabled oil and gas producers to reduce their operational footprint.
For all the benefits of multi-well pads, however, their major increase in size and scope has created a new challenge. The higher density of multiple wells on a single pad increases the equipment required on-site and results in much greater data and control requirements.
The traditional control architectures that have been used for decades are being pushed to their limits and simply may no longer be sustainable. Instead, more advanced control systems are needed to handle the scalable architectures required by modern well pads.
As a result, both operators and the equipment builders who support them must now modify—if not radically change—their control systems approach for these multi-well pads.
Evolution of RTU Technology
Upstream oil and gas producers have relied on remote terminal unit (RTU) technology for well-site control for decades. Initially, the cost of implementing RTUs and the challenges in programming them limited the devices to simple data acquisition and control.
Over time, however, RTUs incorporated more features, including I/O, communications and IEC-61131 programming. These capabilities enabled oil and gas operators to monitor more data points, log history and alarms, and add more complex calculations into the RTUs. Equipment builders and engineering firms also started developing specialty applications for wellhead artificial-lift controls with proprietary microprocessor controllers.
Eventually, virtually every artificial-lift manufacturer had developed its own RTU to control and optimize its respective solutions. Engineering firms also developed their own methods with slightly different RTU applications, while instrumentation manufacturers introduced new instruments to measure just about any process point required.
Recently, however, the increased requirements associated with multi-well pad operations have started to exceed the capabilities of RTU technology.
Devices Pushed to Their Limits
Each well in a multi-well pad requires an artificial lift, flow measurement, equipment control, and level measurement. This creates more I/O and control demand than a single RTU can handle. As a result, oil and gas producers are forced to purchase additional RTUs and spread out application and site control across multiple units.
Oil and gas producers have successfully implemented multiple RTU controllers on a well pad, but they do run into some common problems with these architectures. Some of these problems include:
- Change management of multiple configurations or programs at each well pad.
- Communication management of the many RTUs on-site (e.g., peer-to-peer communications).
- SCADA communications to multiple vendors’ hardware.
- Unreliable execution of custom programs in the RTUs.
The ultimate demand on RTU devices comes when much larger multi-well pad control is needed. This can include an operation with 10 or even several dozen wells on a single well pad. The higher density of wells on a pad also increases the equipment required on-site. For example, many of these well pads have their own separator.
It also becomes more economical to install pipeline compression, vapor recovery units (VRUs) and VRU towers because of the high rate of natural gas produced from the pad. Lease automatic custody transfer (LACT) units, water transfer, and chemical injection machines are also commonly seen on these well pads.
Additionally, many oil and gas producers are investing in electrical buildings known as E-houses. These buildings house main utility power distribution, motor control centers (MCC), network switches and uninterruptable power supplies (UPS), and they are often environmentally controlled.
All of these increases—in equipment, field instrumentation and applications—only compound the common problems with RTU architectures.
They also create new service and support challenges. The use of multiple RTUs has led to multiple application configurations and programs to maintain them. It’s also forced oil and gas operators to work with multiple vendors.
Additionally, having several devices from multiple vendors also requires that workers have more training and experience to support them. While some producers are fully staffed with enough trained personnel to handle the maintenance of the well control systems, many are not. These producers must rely on manufacturer support or contract-engineering support to maintain their control systems.
Moving to Modular, Scalable Control Systems
RTUs have fulfilled their role for decades in handling simple control requirements, simple field-device interaction and simple communications. But they no longer suffice in today’s more complex operating environments.
Many oil and gas producers that have experienced common RTU issues have found a viable alternative solution in the form of a modular and scalable programmable logic controller (PLC). PLC technology has been fine-tuned for years in industrial process control environments that are just as rugged as upstream oil and gas production.
PLCs offer a number of benefits compared to RTUs:
• Modularity: Some RTUs do support modular hardware. But balancing the module requirements with application and control requirements in an RTU is much more difficult than in a PLC. Additionally, third-party modules for RTUs are not typically available because RTUs are not open architectures, whereas PLCs are.
A wide variety of modules are available for PLCs that enable monitoring and control of a wide variety of field instruments. Communication support for many different network types is also supported through modular configuration.
• Scalability: This is important when considering how a multi-well pad is put together. A single well will often be installed at a multi-well site, and it isn’t until months or even years later that additional wells and equipment will come online.
In these instances, equipment builders want to be able to build equipment skids off-site and then simply plug them in and configure them at the well pad. They want to reduce the need for trenching, wire pulling, wire termination, panel and instrument installation in the field to help cut costs. Scalability in both programming and hardware is required in this case, and that’s exactly what PLC technology offers.
• Ease of Programming: Historically, PLCs were viewed as a blank canvas for automation and control. Only engineering firms or experienced programmers knew how to start from scratch and develop the control required in a PLC.
However, modern PLCs have libraries of pre-developed and documented code that can be added quickly in an almost drag-and-drop fashion. Some PLC vendors also have pre-developed upstream oil and gas libraries that can be configured on-site. Oil and gas producers only need to enable and configure the required data from the HMI to start up a PLC, or to add skid hardware into an existing system.
This can eliminate the need for someone like a well technician with specialized expertise to know the programming environment and write new code when adding hardware.
What’s more, program and configuration changes can be made online in a PLC without shutting down the process. RTUs traditionally cannot accept such changes without being taken offline and downloaded. This is a critical differentiator in a modern multi-well pad environment because shutting down the control system results in lost production.
• Remote I/O Functionality: RTUs traditionally have no native remote I/O functionality, but PLCs do. This can reduce costs for installation. Also, when equipment skids are added to a site they can come with pre-mounted and wired I/O and instruments. Startup of these skids is as simple as plugging an Ethernet cable into a switch and configuring the I/O in the controller.
Improving Lifecycle Management
Well pad lifecycle management can be a major headache for operations teams. Wells can go through many different flow states, including natural flowing, electronic submersible pump (ESP) or progressive cavity pump (PCP), and sucker rod pump. And the flow type and lifecycle can vary by well.
Multiple RTUs are often used just to control the well’s various lifecycles. Changing the RTU means changing communication drivers to the SCADA system because the physical RTU at the well is hardware from a new vendor. And configuring the RTU to control the application and setting up that hardware at the system is often a painstaking process.
A PLC-based well pad can provide significant relief in this area, delivering efficiency and optimization benefits that operators may have never thought possible.
By using the modular and scalable I/O hardware architectures that a PLC affords, operators can install I/O modules right where instrumentation is located and send that data to the PLC. And regardless of what I/O design approach an oil or gas producer uses, the hardware in the control system will remain constant, communications to the SCADA system will use the same drivers, and the system will remain online and in control of all applications as updates are made. All the while, there remains just one PLC program to maintain.
There’s also the matter of vendor application support. As already mentioned, many vendors make their own applications for a variety of upstream production needs, and each vendor typically uses a different type of RTU. As a result, vendors can usually only support a few specific applications, not all of them.
PLC vendor support on multi-well pad designs is growing daily. This includes support for equipment-control, artificial-lift, and flow-measurement applications. Equipment automation is easily handled through rich programming environments and a wide variety of I/O and communication modules. Flow measurement also is supported with AGA- and API-compliant flow measurement, calibration support and custody transfer reporting to SCADA systems. Artificial-lift applications, while not as prevalent in PLCs, also are being rapidly developed to support all types of artificial lifts.
Lastly, many oil and gas producers have expressed frustration with RTU applications being “black box.” This means the system is designed with specific inputs that are meant to only control specific outputs.
A black-box approach prevents flexibility as it doesn’t allow oil and gas producers to change the way the system functions. As a result, they either need to change vendors to support their needs or simply live with the technology they have, knowing it’s not functioning as efficiently as they require.
A PLC-based system, on the other hand, can be modified in the field with common industrial tools (IEC-61131), delivering much greater flexibility.
Embracing the New Normal
The PLC has long been viewed as a solution more suited for manufacturing facilities than for well pad control. But today’s modern well pads are, in essence, small factories. They have environmentally controlled buildings, utility or generator power, and much greater data and control requirements.
This makes them an ideal fit for a PLC. A multi-well pad control system that utilizes the modular and scalable capabilities of a PLC can reduce costs and installation times, improve production uptime and ease lifecycle management.
Zack Munk is onshore upstream oil & gas business development manager for Rockwell Automation.