Digital Oilfield Filters Down to Custody Transfer

March 30, 2016
North American oil and gas companies continue to rely more on automation strategies to optimize existing wells. This trend is firmly in place with downstream custody transfer applications.

Market shocks happen and industry players adjust accordingly. A seismic shift in oil prices started in 2014 and since then major and mid-major companies have merged, declared bankruptcies, or moved to optimization strategies relying more on sensing and monitoring in remote field locations.

High-risk megaprojects for major oil producers have been shelved, and a new focus on optimized oil recovery is emerging in shale country.

This optimization shift also has producers reexamining automation for custody transfer applications, where valuable products change hands via flowmeter measurements. Custody transfer, or fiscal metering, takes place at several places within the supply chain—midstream pipeline exchanges, railway intermediaries, liquefied natural gas (LNG) in maritime applications, and trucking operations in fields—and it’s become that much more important to get those measurements right.

The exchanges can include manual metering, but most high-volume producers have been using lease automatic custody transfer (LACT) skids for years. To drive better efficiencies with custody transfer exchanges, producers have been rolling out pilot projects to test the benefits of having more diagnostics in the field and advanced flowmeters, and closing the loop back to a SCADA platform.

One such project is in Eagle Ford, a shale play in Texas where Marathon Oil has a number of oilfields using pipelines to move product to a central facility for minimal processing before entering storage tanks. Early on in the shale operation, Marathon used numerous LACT skids and relied on manual tickets from several trucking companies to conduct custody transfer exchanges.

“We were dealing with about 3,000 tickets a month across the entire assets,” said Kevin McDaniel, SCADA coordinator for Marathon Oil, at an industry conference last year. “We had dozens of operators that were responsible for taking these manual tickets and entering them into our production accounting system.”

Marathon figured it was losing three to five barrels per load. Marathon began optimizing measurements on the LACT skids by testing flow computer calculations and automating a diverter valve on all units.

“Once we had the details worked out with the programming and the physical placement of instruments on the LACT, Marathon created a standard,” McDaniel says. “We went across the entire field upgrading our LACT units.”

With increased I/Os, solar panels provide power to wireless instruments that can connect back to SCADA platforms. Source: ABB

The modernization project cost less than $750,000, and has eliminated risks and losses of about $19.7 million a year. Ticketing has been simplified and truck drivers enter in just two pieces of data: a hauler ticket number and the results of a sediment and water (S&W) sample. With the connection to the SCADA platform and monitoring of the S&W sample, Marathon can now contest any wild differences in total load calculations with the trucking companies.

With numerous field data points in the SCADA system, Marathon can conduct a drive gain report to see how meters are performing across entire assets or look at the instrumentation on the LACT to see if transmitters are working correctly. The upgrade also helps provide more authentication of truck driver transactions, and Marathon would eventually like to fold that into the SCADA platform.

“We’re actually authenticating through the RTU and have a small database of drivers that can load from a specific LACT,” McDaniel says.

Flowmeter trends

Choosing the right flowmeter for a LACT unit is crucial, but there are many applications in this industry. In oil and gas, flowmeters can include Coriolis, differential-pressure (DP), positive-displacement, ultrasonic and turbine—all found in upstream, midstream and downstream locations. Of course, the key with all custody transfers is accuracy—in the range of ±0.15 percent.

“Some companies in the Middle East are running two flowmeters for custody transfer applications in the same line,” says Jesse Yoder, founder of Flow Research. “This can include two turbine flowmeters in the same line, or a turbine and ultrasonic flowmeter. It’s redundancy, but it’s an indication of how critical these custody transfer measurements are.”

Coriolis flowmeters are widely used for custody transfer applications of petroleum liquids, according to Yoder. These flowmeters measure mass flows of liquid via tubes. The diagnostic maturation of these devices are one of the reasons for control being pushed to the edges of oilfields and better profitability.

“Coriolis meters have the ability to intelligently diagnose themselves by a diagnostic called smart meter verification,” says Al Majek, area technical manager for Emerson Process Management. “The meter itself can indicate whether or not it has had any significant shifts or problems by checking its zero, span and the condition of the flowtube itself.” This verification also looks at the meter’s signal processing and electronics, while providing read results on-demand or automatically.

Flowmeter firmware or the flow computer can provide data points on drive gain, volume flow rate and density that help in detecting errors in fluid conditions, such as entrained gas or liquid fractions in a gas stream.

Ultrasonic flowmeters have no moving parts and are very accurate because of multiple sets of transducers in the pipe wall. Since approval by American Gas Association in 1998, ultrasonic flowmeters have been a popular choice for pipeline custody transfer.

“The ultrasonic meter’s growth continues due to the turndown ratio being so high,” says Scott Peterson, sales manager of ABB’s upstream oil and gas solutions business. “The turndown ratio and ultrasonic meter’s robustness continue to make it the probable choice for gas custody transfer applications.” Yoder adds, “The enhanced diagnostic capability—multiple sensing paths—can reduce the need for upstream piping and also increases the ability of the ultrasonic meter to determine sources of error.”

Safety in numbers

In general, LACT units have been multiplying along with the North American shale boom. Some industry insiders put the total number of LACT units in North America at about 30,000 units—an average of 20 wells per LACT for 600,000 producing wells.

During the shale boom and before the downturn in oil prices, LACT unit fabrication was a quick process. But with the push to optimize current wells in the ground, there’s been emphasis on safety with LACT skid applications.

"A few incidents occurred with oil and gas transfers, and the industry is now paying closer attention to safety procedures," says Pete Singleton, vice president of strategic markets for S&S Technical, which makes LACT units for many types of custody transfer applications, including railway and trucking solutions.

“Companies are now more aware of leaks with skid piping and its potentially hazardous outcomes with flash or fire,” Singleton says. LACT units can include a central PLC controlling numerous I/Os, such as grounding verification, overfill, gas detection or flame detection, to name a few.

Most remote shale operations in North America require trucking, but many also include midstream rail distribution points that deliver product to refineries or pipelines. Some midstream terminals can have as many as 20-30 trucking smart LACT units at one facility.

Besides custody transfers via trucking LACT units, tanker filling is another area of emphasis for safety at these terminals.

“Overfill cases have been reported where cars weren’t attended during the filling process and the pump didn’t shut down in time,” Singleton says. “Or where the heel in the car was not accounted for and too much product was metered into the car.”

A fluid situation

Innovation has not always been synonymous with the oil and gas industry, but a new LACT approach from Toptech Systems offers accurate measurement without a PLC and flow computer. The company’s MultiLoad II Skid Control System (SCS) reduces programming in the field by consolidating controls into a single, standard platform. Toptech offers this control hardware to LACT fabricators, along with a Unified Automation Platform (UAP) option for viewing skid data online.

“The SCS module on the LACT unit can work in standalone mode, where it tracks transactions with its own web-accessible database,” says James Imhoff, director of crude and bulk terminal solutions at Toptech Systems. “Alternately, the system can run in a hosted mode, where it’s tied to either Toptech’s UAP solution or a deployed automation program, for the ability to manage an entire network of skids from a single system.”

The control platform oversees pumps, valves, diversion control and flow management for a LACT unit. The cloud-based UAP allows for the LACT operators to see LACT use in real time via a website, print bills of lading, export tickets for billing, run reports on operations, and use an ATG interface for remote tank monitoring. The SCS includes an Ethernet or serial port, and can connect to SCADA systems or trucking terminal management systems.

Maritime applications

As a result of the shale boom, LNG carriers and facilities have made major investments worldwide for the past eight years. For LNG, tankers move product via pipelines and shipping terminals, and conduct many fiscal transactions along the way. Transactions can reach as high as $4 million of product per hour, according to a recent ARC report.

Changes in the way LNG is being sold—20-year contracts vs. spot sales—and commingled inventory is putting pressure on terminals to consider alternatives to the static measurement of ships’ tanks. This static method uses tables for list and trim of the tank, and a variety of calculations for density, volume and others.

Daniel, a division of Emerson Process Management, is using ultrasonic flowmeters to solve measurement inaccuracies because of the danger of the LNG becoming a two-phase liquid if there are hot spots in a pipeline or a pressure drop. Other worries about inaccuracies include discrepancies between calculation standards for LNG and natural gas, and verifying a meter’s performance.

The 3818 LNG ultrasonic flowmeter offers a four-path design, termination cables for cryogenic temperatures, meter insulation packaging and cable routing design. According to Daniel, an overall reduction of 0.2 percent of measurement uncertainty could save as much as $12,000 per hour in financial risk.

This maritime application is just another example of the oil and gas industry reexamining its processes and turning to smarter instrumentation as oil prices dip below $40 a barrel. So after the dust settles from these market shocks, companies will certainly be leaner and smarter than they were before.

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