Do you know Ol’ Lonely? He’s the dressed-in-blue repairman typically depicted waiting for something productive to do since his company’s dependable appliances never need repair. Oil and gas producers in the Eagle Ford Shale and elsewhere are finding that through the services of a similarly encased-in-blue monitoring device, the money spent on produced water disposal can be put to something more productive due to decreased disposal expenses.
The device, a Rosemount 3308 wireless level transmitter, has helped operators realize significant savings and increased safety when the device is installed on storage tanks. Manufactured by Emerson Automation Solutions, the transmitter provides automated real-time readings of the oil and water levels and interfaces in the tank. In these cost-conscious times, these accurate and verifiable readings are providing greater clarity in operators’ oil and produced water inventories.
Determining how much product came out of the ground and where it went with a high degree of accuracy can be a difficult and hazardous exercise.
Manual tank gauging or “hand dipping” is the preferred method as it is viewed as a low-cost, effective solution to manage tank inventory and custody transfer measurements. The American Petroleum Institute (API) 18.1 standard governs the procedure for how these measurements are made. This method is highly dependent on variables like the weather and the accurate reading of the measuring tape by a worker.
“How much oil is in a specific tank? If the answer is sending a worker to the top of the tank to take a manual reading, how accurate and repeatable will that reading be? Will two individuals get the same reading? What if it’s raining and the worker doesn’t want to get wet? Is precision of +/- 1 in. considered good? How about +/- ½ in.?” asked Michael Machuca, director North America Upstream O&G Marketing for Emerson Automation Solutions. “For the size of tank typical at most well pads, ½ in. of oil represents a barrel.”
An operator in the Eagle Ford Shale was disposing about 700,000 bbl of produced water per week at a cost $1.25/bbl, totaling $45.5 million per year in hauling and disposal costs, he said.
“They estimated a 4% to 6% inaccuracy per truck haul as they had no means to verify and were forced to rely on the trucking company’s annotations. At a 5% error rate, this accounted for $2.2 million in avoidable expenses,” Machuca said. “Another operator told us it estimated it was being overcharged eight to 10 barrels per load, which totaled about $1.3 million per year for it in excess saltwater disposal cost.”
In addition to being subject to human error, manual gauging is a worker safety risk. In 2016 the National Institute for Occupational Safety and Health and the Occupational Safety and Health Administration issued a hazard alert (HA3843) on the health and safety risk for workers involved in manual tank gauging and sampling at oil and gas well sites.
Between 2010 and 2014 there were nine fatalities due to tank vapor exposure during the manual gauging and sampling of production and flowback tanks. According to the alert, working on or near the tanks is of particular concern because the tanks contain concentrated hydrocarbon gases and vapors that are under pressure. The opening of the thief hatch directly exposes the technician to the release of these pressurized gases and vapors, potentially leading to the creation of an oxygen-deficient environment. Exposure to this environment can potentially lead to immediate health effects, including loss of consciousness and death.
The first recommendation out of the 10 listed in the alert is to implement alternative tank gauging and sampling procedures that enable workers to monitor tank fluid levels and take samples without opening the tank hatch. In response, API 18.2 was issued. The standard allows for custody transfer of crude oil from lease tanks using alternative measurement methods that are more practical and economic for small lease tanks.
“While there has been an existing standard API 3.1B for automated tank gauging for custody transfer measurement, this standard was designed for large storage tanks with requirements that are not practical and are not economical for small lease tanks,” Machuca said.
An acceptable solution by API 18.2 is the use of a guided wave radar to measure the volumes and interfaces in the production tanks.
“Guided wave radar is based on microwave technology. Microwaves are only affected by materials that reflect energy, which means that temperature variations, dust, pressure and viscosity do not affect accuracy,” Machuca said. “The device sends a low-energy microwave pulse down a probe. When the pulse hits the media, a significant proportion of the energy is reflected back up the probe to the device. The level is directly proportional to the time-domain reflectometry.
“Because a proportion of the emitted pulse will continue down the probe, an interface also can be detected. This is especially useful to detect the presence of oil in the water tank. When microwaves hit the oil surface, some are reflected back, and some continue through the oil.”
He continued, “The reflected microwaves provide the level reading, and the microwaves that continue through the oil will be reflected back on the water surface. These microwaves then provide the interface reading. With this reading the operator can schedule a technician to remove the oil from the water tank, ensuring it is not lost to the saltwater disposal facility.”
Microwave pulses are sent out by a transmitter installed at the top of the tank. As the pulses travel through the oil (in brown) or water (in blue), the actual level measurement is taken as a function of the time taken from when the signal was emitted to the time at which the echo from the media (be it oil or water) is received. (Source: Emerson Automation Solutions)
Guided wave radar devices have no moving parts and are virtually maintenance-free. The devices are available in a wired and a wireless model, with the wireless model powered by battery.
All instruments and diagnostics used by the automated gauging system can be brought into a central controller or remote terminal unit. Human-machine interfaces are used to automate haul transactions using either manual or automatic tank gauging.
Solutions for remote operations include flow computers and remote terminal unit platforms with flexible software applications and SCADA systems to monitor the process of fluid transportation. Operators using Emerson’s Tank Manager application, traditionally used for oil hauling operations, are seeing the benefits for applying that same technology to saltwater disposal.
“After one operator estimated a reduction of $15 million worth of fiscal risk by formalizing and automating its metering of oil at its production tanks, it decided to extend the same process to manage its saltwater disposal and expect $1.3 million in savings on its disposal cost,” Machuca said.
As a solution to its $2.2 million in avoidable expenses, the Eagle Ford Shale operator deployed 800 copies of the Tank Manager application. Internal results show a 5% reduction in error or inaccuracies, he said. Cost savings are estimated to be $2 million per year based on current drilling and production rates across 2,000 wells and with oil prices at or near $60/bbl.
Applications like Emerson’s Tank Manager transitions the recording of haul details from a paper ticket to an automated real-time capture of data like tank levels, truck driver identification, fluid characteristics and information about the haul. (Source: Emerson Automation Solutions)
Contact the author, Jennifer Presley, at firstname.lastname@example.org for more information.
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