Storage is an integral part of gas distribution systems throughout the world. Different types of underground storage sites are a fundamental part of such systems. Sites that typically play a part in an overall gas distribution system include salt domes, abandon mines such as salt, coal, etc., depleted oil and gas reservoirs, and man-made vessels.
The requirement to precisely measure and control gas flow into and out of facilities is critical for both safety and financial reasons. Moreover, storage sites are increasingly involved in custody transfer and gas mixing operations. The demanding measurement accuracies and control requirements these applications pose are often at odds with what existing legacy technologies provide.
The gas storage location involved in the following application was once a producing gas well. It is conveniently located, providing access to primary gas transportation pipelines and main hubs for final distribution to major metropolitan areas. It recently underwent an upgrade, moving from a legacy system to an “all-digital” fieldbus-based infrastructure.
The site stores natural gas for multiple clients on-demand. It primarily serves as a supply cushion during the peak season (November through March). The majority of gas is injected during the low season (April through October), while the majority of gas is withdrawn during the peak season. Gas is also injected and withdrawn on demand throughout the year, as clients have spot market orders that must be fulfilled.
The existing location has four injection/withdraw wells that are currently in operation. This exercise was made possible by the addition of four additional injection/withdraw wells. Two more wells may be added at a later date. The multiple wells not only allow for increased injection volumes, but also provide alternate wells for maintenance purposes (Figure 1).
Figure 1. Multiple wells provide increased injection volumes and backup systems for maintenance.
The existing wells are equipped with various control hardware. Subsurface valves allow for isolation of the injection lines and are controlled to open/close position with solenoid valves. Control valve positioners, differential pressure (annubar), pressure, and temperature transmitters are used to control gas flow into the reservoir as well as measure line conditions for proper volumetric corrections. All existing instrumentation is conventional 4-20 mA tied to programmable logic controllers (PLCs). The PLCs not only carry out the controls requirements of the site, but also calculate volumetric corrections on the gas. An emergency shutdown system (ESD) is also incorporated into the overall scheme (Figure 2).
|Figure 2. An emergency shutdown system is incorporated into the overall system.
The system architecture includes human machine interfaces (HMIs) via a fiber-optic network and Ethernet hubs tied to the PLCs. The existing communication protocol is Modbus.
Several factors justified the implementation of this technology in this installation. The addition of new wells required installation of additional hardware and controls. It also potentially required replication of the existing controls building at the physical well site.
It should be noted that this facility is located in a rural, agricultural, and environmentally sensitive area. The property owners insisted that every effort be taken to minimize visual impact. With this in mind, it was important to reduce the physical hardware and facilities as much as possible.
After carefully researching Foundation fieldbus protocol, the well owners felt that several benefits could be realized through its implementation. They included:
• Reduced engineering costs
• Reduced hardware costs
• Reduced installation costs
• Reduced visual impact at site
• Improved control capabilities
• Reduced operational and maintenance costs
It was important that the system incorporate both existing features and new requirements. Using existing network hardware and HMI stations was a priority.
Figure 3. Flow computers are connected to network servers and workstations via Ethernet switches and fiber-optic cables.
System operational requirements included: automated low- and high-pressure overrides (for primary flow control); automatic sensing of flow direction; comparison to other custody-transfer flowmeters on location; use of existing annubar probes as primary measuring devices; and the ability to produce meter reports for individual meter runs.
Individual meter reports had to provide values for total accumulation on injection and withdraw including: today”s rate (MMCFD); today”s rate flow time (HRS); today”s total (MMCF); yesterday’s total (MMCF); and yesterday’s flow time (HRS). Industry standard software configuration tools and devices supporting a wide variety and quantity of function blocks rounded out the system requirements. A fieldbus control system (FCS), which included a flow-computer component, was chosen for the application.
Use of the existing HMI was supported through OPC connectivity, and existing network hardware was easily integrated. Configuration tools and transmitters supporting up to 20 function blocks each offered maximum control and configuration options.
|Figure 4. The software provides documentation for process analysis.|
System components included flow computers connected to network servers and workstations via Ethernet switches and fiber-optic cables (Figure 3). Transmitters, including pressure, differential pressure, temperature, and valve positioners for individual meter runs were subsequently connected to the flow computers via individual H1 segments.
These segments (H1) are the individual instrument networks supported by this technology. They provide power and communications on a single pair of wires for up to 16 instruments per network. The Foundation protocol is used at every level of the architecture. This includes the upper-level network (known as HSE) from the engineering/workstations to the individual flow computers and the instrument network level (known as H1).
System configuration was performed using an open/standard configuration tool called Syscon. This software is an OPC client, which communicates to the linking devices and their related instruments through OPC servers. These software servers are located on the network system hardware servers. This tool configured both network communications to the linking devices (FC302), as well as the subsequent programming of field devices on the individual segments, and their associated function blocks. The software is by its very nature self-documenting (Figure 4).
Figure 5. The instrumentation is centralized for individual meter runs.
Controls configuration involved a number of different control schemes including the overall control strategy, implementation of AGA3 and AGA8 custom function blocks, flow accumulation, and ESD strategy. Both standard and custom function blocks were used in the configuration. Other features supported by the configuration software include in-depth diagnostic tools, which provide online diagnostics, operational, and troubleshooting capabilities.
On-site installation time was minimized by various factors. Elimination of multiple cables and the use of well-pad instrument enclosures contributed greatly. Single H1 segments were used for individual meter runs, reducing wellhead cabling by as much as 75 percent. Incorporating individual well-pad instrument enclosures served several purposes including: raising instruments above annual flood levels, as the well-pads are in a grassland that floods to a depth of two to four feet during the rainy winter season; centralizing all instrumentation in individual enclosures for individual meter runs (Figure 5); and incorporating quick-connects for both process and electrical connections, resulting in reduced diagnostic and maintenance costs (Figure 6).
|Figure 6. Quick-connects are provided for both process and electrical connections.|
The time required for commissioning and startup was reduced more than 60 percent. The single largest factor reducing overall project costs involved the elimination of an additional instrument building. Previously, all instrumentation was mounted to the outside of this structure. Had this project utilized conventional instrumentation, this building would have been duplicated.
Implementing new technologies in any application results in challenges and lessons to be learned, and this project was no exception. While positive outcomes, such as decreased engineering, equipment, and installation costs were realized, other challenges resulted that will be taken into consideration on future projects.
New technologies result in learning curves for all personnel involved. Efforts should be taken to ensure all project and maintenance personnel understand the differences between the newly implemented technology and resident legacy systems. Recognizing the differences and understanding how to use the new technology can easily be accomplished through training. Any effort to migrate from or replace legacy technologies should include training for all personnel involved. This should be an integral part of any project implementation.
Significant savings were realized in this project. An additional instrumentation structure was completely eliminated; and the project would still have proven economically advantageous even with an additional structure. The overall system savings comparisons are conservatively reflected in the above table.
With the success of this project on the new well pads, plans are now in place to migrate controls on the existing four wells to the same system. Integrating asset management capabilities will be an integral part of this planned migration as well.
As this project reflects, the use of an all-digital FCS in gas storage applications shows great promise. While project economics reflect significant project savings, other advantages are inherent to the technology. Open system architecture, true distributed control, diagnostics capabilities, and a single communications and control protocol have resulted in an extremely versatile system. The presence of compensated flow computation, control, emergency shutdown, and monitoring in a single system platform make fieldbus technology an excellent choice for gas storage, as well as other oil and gas applications.
About the Authors
Dave Evans is oil & gas business development manager with Smar International. In this capacity, he works with domestic and international oil & gas companies, primarily focused on instrumentation and controls as applied to production, transportation, and distribution applications. Mr. Evans has more than 17 years of experience in the instrumentation and controls industry. He can be reached at email@example.com or 713 849-2021. Ed Morrison is senior applications engineer with Oleumtech. His primary focus involves instrumentation, controls, and wireless communications applications as they relate to the oil and gas industry. Mr. Morrison has been involved in the implementation of flow computers and control systems in a wide variety of measurement applications. He can be reached at 832 465-0034 or firstname.lastname@example.org.
This article is based on a paper that was awarded “Paper of the Year” for the ISA Technical Division at ISA Expo 2004.