Smart Instruments Change Operations for the Better

Dec. 6, 2022
Occidental Petroleum, Wildfire Energy, and Gore Nitrogen show how the ability to take multiple measurements with a single device make smart instruments a natural for enhancing real-time decision making.

Critical manufacturing and process control instrumentation is steadily gaining smarts, allowing companies to collect and analyze a smorgasbord of data at pivotal points in their operations, leading to cost reduction, higher output and efficiencies, and enabling predictive maintenance.

Process control engineers have long used instruments to measure temperature, pressure, fluid flow, and other key values to ensure a high degree of accuracy and safety for industrial operations, particularly in process-oriented industries like oil and gas, petrochemical, and wastewater treatment. Traditional, “dumb” instruments were typically used to take stock of a single measurement, often displayed through physical gauges, with reliance on human technicians to patrol operations, manually record and interpret data, and then facilitate any necessary corrective actions.

The advent of more powerful onboard microprocessors and multiple digital network communications capabilities have laid the groundwork for more intelligent instrumentation capable of measurement and diagnostic capabilities beyond the scope of their primary charter. As opposed to traditional instrumentation that needs to communicate any of these process values to an external control system for interpretation and action, smart instruments are outfitted with intelligent sensors and, oftentimes, edge capabilities that convert data to a usable, digital format without an intermediary. As a result, smart instruments can make data available in near-real-time to drive decision-making, whether that’s to recalibrate a process or initiate a particular maintenance action.

In addition, smart instruments are typically associated with web server functions, mobile apps, and Bluetooth capabilities that allow remote workers to monitor status, collect operational data, and initiate corrective actions without having to physically be on-site.

“Electronics and technology have evolved to allow instruments to have a lot more functionality at a similar price point,” says Mason Flannery, product marketing manager for flow at Endress+Hauser. “Data-driven decision making is having an impact in every aspect of life, and it’s the same in automation and process control. The ability to take more than a single measurement value delivers additional information that can drive diagnostic decisions and increase the value of a single instrument. This reduces costs while increasing safety, quality, and production efficiencies.”

Fueled by adoption of Industry 4.0 technologies, including the Industrial Internet of Things (IIoT), demand for smart industrial sensors and instrumentation is surging—with the market expected to grow at a 9.6% CAGR from 2022 to 2029 to reach $22.6 billion, according to a report by Meticulous Research. To get a sense of what’s driving this momentum, we’ll look at the three companies using smart instruments to help field personnel accomplish more without investing in additional physical devices to optimize production and operational efficiencies.

Occidental Petroleum Corp. When a site is pumping 70,000 barrels of oil, 320 million cubic feet of natural gas, and 4,000 barrels of natural gas liquids (NGLs) every day, there is no appetite for downtime.

Yet Occidental Petroleum Corp., an international oil and gas exploration and production company, found itself dealing with the possibility of a temporary shutdown of its Catarina, Texas, site to fix a complication with a standard treatment process to clean up the natural gas feeding its wells. The normally granular replacement carbons used during treatment were morphing into a porous, solid mass, transformed by liquids in the gas stream. What was usually a manageable task had turned into weeks of work by on-site workers, racking up maintenance costs of about $800,000 and dramatically reducing processing capacity at the Catarina site as multiple towers went offline during the clean-up effort.

“Not only did the liquid cause huge problems with the treatment towers, it also represented lost income of about 12,000 barrels of natural gas liquids each year, impacting the site’s profitability,” noted Chris Diaz, a senior automation engineer at Occidental.

After comprehensive analysis, the temperature of incoming gas was determined to be the culprit. During cooler months, a variance of a few degrees created an environment where liquids condensed, creating the complications. The fix called for a mechanism to monitor and control gas temperature so that it remained above the dew point. This remedy would have required welding thermowells into existing piping to accommodate multiple temperature measurement points—a process that would stop production at roughly 100 wells feeding the facility with a downtime price tag of about $1 million a day.

Occidental opted for a different path. Using Emerson’s Rosemount X-well intelligent transmitter, combined with a WirelessHART transmitter and internal power supply, the team devised an alternative solution that didn’t require penetration or welding, thus avoiding the pipeline’s shutdown.

The new smart instrument setup measures both ambient temperature and internal temperature, performing corrective calculations to achieve continuous, accurate, and repeatable readings of the gas inside the pipe. Data is sent to the automation system using WirelessHART, and the system gives operators a great deal of intelligence compared to what they had with the singular temperature reading.

“When all the possibilities were examined, measuring temperature using the surface-mounted transmitters and a WirelessHART network proved to be, by far, the lowest cost option,” Diaz said.

When changing up traditional temperature or flow instrumentation for intelligent replacements, process engineers must now think beyond doing a like-for-like replacement, cautions Kyle Knutson, Emerson’s director of marketing. “You’re not just looking at something that can save you time or money, you should also consider what can be done by having more data to analyze about your process or plant that you couldn’t get with traditional instrumentation,” Knutson says. “Otherwise you might miss out on how you can run your plant more efficiently and get more actionable data.”

Wildfire Energy An independent exploration and production company focused on developing oil and natural gas resources in Texas’ Eagle Ford, Wildfire Energy operates more than 550 wells, overseeing a production process that typically required gauging of physical tank equipment to obtain accurate oil measurements. In addition, each of its wells required a dedicated three-phase separator and storage tank to orchestrate proper allocation of resources—a configuration that was costly to implement and maintain, requiring personnel to be deployed onsite to monitor tank conditions.

To reduce both man power and equipment, Wildfire Energy initiated a pilot project to replace legacy instrumentation with an ABB Smart Coriolis meter, an update that reduced the number of physical devices required while also allowing for integration into a SCADA system whereby real-time flow rates could be monitored along with density and pressure from oil production. The new set up also enabled daily volumes to be maintained based on a total flow calculated to meet industry standard volume metrics, according to Bryce Weempe, territory account manager for ABB. Another upside is that the Smart Coriolis meter introduced full diagnostics to alarm in cases of internal tube erosion, process upsets, or meter malfunctions.

“Operators can use less production equipment as they now comingle different allocation wells by using Coriolis technology upstream instead of storage tanks,” Weempe explains. “This is a more accurate, efficient, cost effective, and safe way to measure hydrocarbons on a production location.”

When implementing smart instrumentation like Coriolis meters, it’s important to consider technologies that can be easily managed with software, including to commission and check device health. ABB helps customers address these issues by providing on-site training along with its My Measurement Assistant app to provide check lists and You-Tube-style videos for troubleshooting instruments.

Vanessa Klekar, U.S. instrumentation technical sales manager for ABB Measurement & Analytics, says engineers, operators, and technicians need to be open-minded about making changes in their processes to reap the full value of smart instrument technology. “If you have team members that refuse to utilize the benefits that smart instrumentation offers, it’s not doing much good,” she says. “You have to be willing to learn something new and not be too comfortable doing things the way you’ve always done them.”

Gore Nitrogen
Managing its limited field personnel and time was a constant balancing act for Gore Nitrogen, which delivers an array of specialty services for the industrial, pipeline, and oil field industries.

To maintain optimal safety and high-quality pumping conditions for its customers’ wells, the company regularly deployed personnel on-site to manually take viscosity measurements every 10 minutes. Because the products were non-Newtonian fluids with fluctuating viscosities, Gore Nitrogen couldn’t set specific levels, requiring them to make timely adjustments to ward off potential safety or quality issues.

“We constantly have to take measurements of the process to verify to the customer that we are at the correct viscosity,” explains Brandon Bensch, IT director at Gore Nitrogen. “This involved a person having to pull a sample, take it to the mobile lab, and run it through a manual system. The human factor alone had a variety of potential issues—spills, contaminated samples, interpretation of the manual system’s metering, wasted manpower, etc.”

With help from Endress+Hauser, Gore Nitrogen installed the Proline Promass I 300 Coriolis flowmeter along with the RIA46 field indicator to deliver multiple measurements from a single device and provide readings in a familiar format. In this case, the company was able to gather flow, density, temperature, and viscosity measurements in a single device, eliminating the need for multiple transmitters and enhancing the overall usefulness of each measurement.

With this new flowmeter, there is no longer a need for manual testing, freeing up field resources to focus on other tasks. In addition, manual samples are no longer pulled every 10 minutes, nor are regular tests required for measurement readings; instead, corrections are automatically made via the control system, which improves accuracy and overall quality for each customer’s job.

“The biggest benefit we were able to achieve was repeatability,” Bensch explains. “When we were taking samples manually, you could run the exact same sample two or three times and get two or three different results depending on how the sample was interpreted. We proved the repeatability of the Promass I 300 in our lab and in the field. There is just no matching the consistency of the results.”

The Promass I 300’s built-in web server delivers additional value, especially for remote operations. “At any given time, we can log in and check settings to see how the system is reading,” Bensch adds. “That provides big savings on technicians in the field, greater transparency for the customer, and allows for additional observations to prevent issues like leaks and spills.”

While the Promass I 300 was more expensive than a traditional flow measuring device, the added costs were counterbalanced by not having to invest in multiple devices. “You’d have to physically find space for four separate instruments plus take into account any insulation and wiring considerations,” says Mason Flannery, product marketing manager of flow technologies at Endress+Hauser. “Calculating the time it takes for an operator to run samples each time in a non-automated format also factored into the decision point.”

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