Analyzing Critical Flow Measurements
The need to measure large-volume flow (how much gas or liquid has moved from point A to B over a specific period of time) with precision advanced many years ago when energy purchasers (e.g., oil, gasoline, natural gas) started questioning seller’s invoices. This led engineers to develop mechanical flowmeters using paddlewheel and propeller techniques in the pipeline to “count”...
The need to measure large-volume flow (how much gas or liquid has moved from point A to B over a specific period of time) with precision advanced many years ago when energy purchasers (e.g., oil, gasoline, natural gas) started questioning seller’s invoices. This led engineers to develop mechanical flowmeters using paddlewheel and propeller techniques in the pipeline to “count” the amount of flowing material. Unfortunately, these systems weren’t always very accurate and were prone to mechanical breakdown, but at least the buyer and seller had some basis for agreement.
As technology advanced, custody transfer applications expanded to include more accurate and reliable techniques such as magnetic field, positive displacement, and ultrasound. However true flow calculation needed to consider other measurements and conditions: temperature, pressure, pipe diameter, and material purity all matter. Because these attributes are dynamic and can change frequently over time, a way to measure these variables continuously and then calculate flow was required. The concept of a flow computer evolved precisely for this purpose.
Flow computers monitor data from flowmeters while simultaneously collecting information from other sensors such as temperature, pressure, density and chemical analyzers. Computers process the data using standard based algorithms to calculate mass or volume flow. Often flow computers are installed in remote areas where LACT (leased automated custody transfer) units are located such as offshore oil rigs, pipelines, tank farms and compressor stations. The resulting flow information can be displayed locally or transmitted into a computer system.
As energy systems grew and telecommunications advanced, DCSs (distributed control systems) became more practical. This required the collection and transmission of flow information from the pipeline to a central collection point. Remote telemetry units (RTUs) were used to store and transmit flow information as part of a remote supervisory control and data acquisition (SCADA) network. RTU and SCADA networks often used Modbus communication because of its multi-point (polled) architecture. Finally, PLCs were installed to handle electrical control of valves and compressors, and to safely shut down processes during emergencies.
Today, measuring flow is often accomplished by installing a flow computer to several meter runs and then feeding the information to an RTU. While this is effective, it requires integration and wiring of many field devices. Additionally, stand-alone flow computers are relatively expensive and often limited to only a few meter runs.
Measuring large quantities of liquid and gas hydrocarbons requires careful analysis of fluid characteristics in addition to volume.
Integrating flow measurement
PLC technology has significantly expanded to support many functions well beyond discrete control and simple data collection. Modern PLCs include many process control functions (such as PID loops and recipes) while offering a broad range of communication options and data management tools. The key is that PLC processor power, near real-time I/O speed and flexible networking options makes this platform ideal for just about any challenging industrial application including accurate flow measurement.
However while PLCs offer excellent performance, their programming is typically optimized for sequential control. Burdening the PLC program with complicated calculations (such as flow algorithms) is not good practice especially when multiple meter runs are required. This presents a challenge for using PLCs as complete flow measurement solutions.
One approach to solve this problem is to embed flow computer functions in a PLC module providing an integrated PLC, RTU and flow computer. There are several advantages to this approach.
First, the flow computer module can use its own onboard, high speed processor for flow calculations and memory for data archiving. This approach does not burden the PLC processor no matter how many meter run calculations are occurring.
Second, the module can read input information (flow meter, pressure, temperature, etc.) directly from the PLC over its high speed backplane. This means that the PLC program not only manages I/O functions for other processes (such as valve control and alarm monitoring) but also gives the flow computer module access to this information at high speeds.
Third, the PLC can read flow measurement data directly as I/O register information. The PLC ladder program can then use this information for alarms and controlling process loops.
Finally, archived data within the flow computer module’s memory is available to the SCADA network via Modbus communication. This functionality is ideal for hybrid PLC, DCS, and SCADA systems offering an easy approach to technology migration.
The resulting system combines all standard functions into one platform, thus simplifying design and reducing installation time, while offering flexible communications options.
Standards and certifications
As with traditional flow computers, flow computer PLC modules must also comply with hydrocarbon calculation standards to ensure accuracy and to satisfy custody transfer requirements. Standards are important because they define flow calculation algorithms and provide a common, unbiased measurement method to which all parties can agree upfront. Using standards greatly reduces custody transfer disputes and provides an easy way of doing business with multiple parties.
As a means of addressing these issues, a group of standards organizations responsible for petroleum measurement were created: AGA (American Gas Association), API (American Petroleum Institute), GPA (Gas Processors Association), ISO (International Standards Organization), OIML (Organization Internationale de Metrologie Legale, or International Organization of Legal Metrology) and others.
AGA and API are the oldest and most widely recognized hydrocarbon standards organizations in North America, and publish many standards including AGA 3, 7, and 8, and API 2540. However, neither association tests or certifies flow computer devices. In fact, certification is not necessarily a requirement as many producers and consumers periodically field test the transfer system to ensure accuracy. At the same time, certification may be required due to local regulations or agreement by transfer parties and is often required by law for some classes of transactions.
Certifications are issued by testing organizations, typically either government regulatory agencies or independent testing labs whose reports are accepted by such agencies. Such organizations include Measurement Canada (a branch of Industry Canada, a ministry of the Canadian Government), UL (Underwriters Laboratories Inc., accepted in most places worldwide), and LNE (Laboratoire National de Metrologie et d’Essais, accepted by several European countries).
Embedding flow computer functions into a PLC platform offers many process and financial benefits. Cost savings are immediately evident because PLCs are typically already part of the control system and an embedded PLC module is often far less costly than a traditional external flow computer.
Most PLC based systems support eight to 16 m runs while traditional flow computers may be limited to as few as four m. Space savings also are evident as additional special cabinets or panels are not required to house the flow computer, just an open slot in the PLC.
Backplane communications provide easy integration of sensor I/O, without the need to match fieldbus protocols and interfaces to the flow computer. Because PLCs offer a very wide range of I/O options, the sensor wiring and interfacing are simple. There are no special requirements to match sensors to the flow computer interface, saving time and expense. Reducing the number of field devices has direct impact on installation time and labor costs as there are fewer devices to install.
Perhaps the most significant benefit of using an in-rack flow computer is the seamless communications provided directly to the PLC platform. Most PLCs now support Ethernet communications and many serial protocols. Once flow information is made available to the processor, the network has full access to this data. Remote SCADA, HMI, data collection, historian, and maintenance applications can easily access this information, providing very flexible and economical communications. Some flow computer modules also provide Modbus ports for direct connection to Modbus flow meters or as slave connections to legacy SCADA systems.
Part 2, in January, will cover two application case histories.
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