Upstream operations teams are smaller these days, but the demands of the onshore field remain the same. Operators still have to manage thousands of wells spanning large geographic regions, most of them in rural territories. Wellheads have some basic automation, but the SCADA system might not be reliable enough to detect a sensor alarm that leads to an overflowing storage tank. Fines for detectable emissions at a storage tank can reach $15,000/day in many U.S. shale plays, so it should be no surprise that leak detection continues to be a high priority across the value chain.

When a leak is suspected, one option is to immediately dispatch a technician to the site without any indication of the specific problem. The actual time to site could be a few hours depending on the size of the field and the condition of the roads. The technician arrives onsite but has trouble finding the source of the leak, so he or she tries to get in touch with a more experienced team member and report visual status. Spotty cellular service prompts the technician to drive to a nearby hilltop to make the call. The expert might be busy helping other junior technicians address problems elsewhere in the field and does not answer the phone. Meanwhile, the clock is ticking.

As the clock ticks on for the leaking storage tank, consider a few alarming figures: 50% of the oil and gas workforce is retiring in the next five to seven years. Two people retire as one new employee enters the workforce. The gap between ages 35 and 55 is in the tens of thousands, and it raises many issues for oil and gas companies that rely on skilled and experienced operators to run their fields. This phenomenon has been dubbed “The Great Crew Change.”

The younger generation and tech-savvy senior operators expect a more digital, connected production environment with decision-making based at least in part on dashboards and data. “That mindset from some younger workers who are more data-driven, more empirical, less intuitive is probably the prevalent mindset and the way companies will be run in the future,” said Oklahoma Oil and Gas Association President Chad Warmington in a Jan. 1, 2016, article in the The Oklahoman.

A visit to a field office of any major producer will certainly validate Warmington’s statement. Desks are lit up with computer screens showing alarms, graphs and other data visualizations that can make maximizing production volumes and optimizing resource allocation seem almost like a video game. There’s nothing wrong with a little friendly competition in the workplace.

Equally as important are the more traditionally minded senior operators who rely on experience and intuition to guide them in the field. In many ways there is no substitute for time spent at the plant or on the well pad solving everyday challenges year in and year out. As resistant as they might seem to change, this group will definitely embrace new technology if it makes their lives easier. For evidence, just consider the tiny supercomputer, or smartphone, that goes with people everywhere every day.

Real-time monitoring, control

Switching back to our leaking tank scenario, could it have been avoided? What if the field network had the bandwidth to support real-time monitoring and control, with video analytics software adding another layer of intelligence on top? Modern private wireless networks enable the technician troubleshooting the leak to transmit a live video image from a head-mounted camera, while engineers at the field office remotely pan and zoom in to visually inspect the equipment from the same viewpoint.

The team can collaborate and formulate a game plan to fix the problem within minutes of using the network. Because he or she can order parts in the system and check email from the field, the technician knows to pick up the right materials at the warehouse before heading back out to the site. When the technician arrives at the well pad, a video messaging application can show others the status of repairs as they happen. By enabling smart remote monitoring and video calling applications, the field network already is saving the company precious hours of downtime, but with analytics software connected to the SCADA historian, the operators also might have been able to predict a failing level sensor and avoid a tank leak altogether.

Increasing efficiency, lowering costs

Producers also must consider the cost of operating a vehicle fleet. One operator reported that its San Juan Basin operations team drives more than 12.8 million km (8 million miles) per year, covering a territory that spans 14,504 sq km (5,600 sq miles). Operators who repeatedly interrupt their routes to return to the field office to access production application data can easily multiply their daily driving distances. This waste of time can be avoided if they have reliable access to the same data while in the field.

A gathering company in the same region reports that after it implemented a private broadband wireless network for vehicle and well pad communications, it lowered daily driving distance from 483 km (300 miles) to under 161 km (100 miles) per operator. Field technicians nolonger had to drive to the top of the nearest mountain to pick up cellular coverage from towers located in the adjacent valley. Instead, the private network automatically formed mesh links between existing radio towers and poles mounted at the well pad, creating coverage in targeted areas. In each vehicle the operators use high-power radios to connect into the mesh network even if they are miles from the nearest well pad. This is a huge advantage over the past scenario, in which operators became frustrated with ongoing cost and low performance of cellphone radios and signal boosters.

Custody transfer is another function that can be automated to significantly improve measurement accuracy, particularly in fields where materials are transported by truck. The custody transfer process has traditionally been tracked manually via paper tickets. Tickets get lost, and volumes get misreported, which results in significant discrepancies and lost revenue.

There was much less focus on volume lost in custody transfer when oil was trading at $100/bbl. These days every drop counts. The custody transfer process can now be entirely automated, and real-time data can be sent to the field office as well as the midstream partner receiving the product. The product received can be reconciled immediately and, most importantly, accurately. Using automated custody transfer applications with digital meters and flow computers that communicate over a modern wireless network, producers can now be sure that they are paid for the exact volume transferred to the midstream partner.

For today’s upstream field, moving to a modern wireless network that uses all available spectra, both licensed and unlicensed, coupled with intelligent radio resource management software that both mitigates interference from other sources and minimizes self-interference, makes the most sense. Such a broadband wireless network offers multimegabit speeds and high reliability, which are essential for real-time SCADA and video collaboration. The sub-1 gigahertz narrowband frequencies are still the most economical way to reach remote sites, especially those running on solar and wind power; therefore, the intelligent combination of frequency bands and radio technologies is still a necessity. One thing is for sure: One size does not fit all when it comes to oilfield communications.

With modern network connectivity throughout the field, teams can reliably access data to make better, timelier decisions about the health of the remote asset, possibly delaying an emergency site visit to a future scheduled trip. Because they spend less time on the road, teams are safer, more productive and able to meet the daily challenges of upstream operations.

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