Manual tank gauging is very prevalent in onshore oil and gas facilities located in the United States. It is viewed as a low-cost, effective solution to manage tank inventory and custody transfer measurements. The API 18.1 standard governs the procedure for how these measurements are made, but there is increasing concern around accounting accuracy, production losses and safety. Operators are also looking reduce costs and increase cash flow by better managing tank transfers, logistics and inventory.
Until recently, the only other solution was to install an expensive lease automatic custody transfer (LACT) unit, which can be uneconomical on sites with low production volumes. To address this issue, the American Petroleum Institute (API) has released a new standard API MPMS Chapter 18.2, Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods, which allows for custody transfer of crude oil from lease tanks using alternative measurement methods. 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.
The industry realized the benefits to a more automated method of measurement. Because of this need, API took up the responsibility to issue a new standard API 18.2 to address the unique requirements of small lease tanks in onshore oil & gas operations. API 18.2 now considers guided wave radar level measurement as an acceptable solution and references the exiting API 3.1B standard but with reduced accuracy requirements associated with API 18.1 that are that are more suitable for smaller tanks.
Guided wave radar has been traditionally used to provide validation of well production rates and off-lease transfers of produced water and tank gauging operations for oil custody transfer. Many oil and gas operators have standardized on guided wave radar technology and will see significant additional benefits in using this technology for custody transfer from a safety perspective—by keeping personnel off of tanks.
Manual tank gauging presents a number of health, safety & environmental (HSE) concerns associated with frequent trips into the field. These trips include working under harsh seasonal weather conditions and being exposed over time to volatile organic compounds (VOCs). For example, opening thief hatches can lead to the rapid release of high concentrations of hydrocarbon gases and vapors. This may result in very low oxygen levels and toxic hydrogen sulfide (H2S), as well as flammable conditions around and over the hatch.
Workers have experienced dizziness, fainting, headache, nausea, and, in some cases, death, while manually gauging tanks, collecting samples, or transferring fluids. National Institute for Occupational Safety and Health (NIOSH) researchers, along with officials from the Occupational Safety and Health Administration (OSHA) are investigating these cases and other reports of worker deaths (9 identified 2010-2014) associated with manual tank gauging and sampling operations in the oil and gas industry.
Eliminating hand gauging and utilizing automated technology can reduce the risk to workers as outlined in recent NIOSH-OSHA Hazard Alert. In addition, better insight into tank inventory levels can reduce the risk of spills and can be used to optimize transfer logistics reducing road traffic hazards.
Accuracy & Lost Production
Manual tank gauging requires high operator competency, is subjected to human errors, and often must be taken under difficult weather conditions. When oil is hauled off the lease site, the operator must ensure that the volume delivered is not less than what was measured in order to be contractually compliant. This can lead to rounding off open and end level measurements, which can introduce lost and unaccounted for production errors.For example, a one percent error in tank gauging on typical shale production well producing 900 barrels per day represents an annual fiscal exposure of $164K at $50 per barrel oil (Figure 1). One operator’s efforts to verify the extent of measurement variability within a team of gaugers indicated volume discrepancies where actually as high as ±8%.
Lack of visibility to production separator upsets will send oil to the water tank or water to the oil tank. If not detected, oil in the water tank will be lost, especially if using a 3rd party water hauler during water transfers.Unaccounted for or unauthorized hauling of produced oil in the water tank from a multiple well pad facility could reach over $1,000,000 a year in lost revenue if not accurately monitored and recovered (Figure 2). Excess water in the oil tank can lead to an unexpected oil tank capacity loss resulting in a spill or well shut-in from a high-level alarm.
Many O&G operators are now realizing the economic benefits of automated level measurement solutions such as guided wave radar to ensure accurate inventory measurements, prevent spills, optimize transfer logistics, and verify custody transfer measurements. Leveraging wireless guided wave radar technology has added advantages that can reduce installation costs by as much $24k on a 4-well pad according to a recent case study by WPX Energy. Diagnostic capabilities and interface measurements can be used to detect if oil or water has been transferred to the wrong tank to minimize lost production and provide insight to correct separator problems.
In conclusion, the application of wired or wireless level technology for continuous and point-level monitoring improves production management by enhancing operations. Continuous insight into actual inventory levels helps avoid reactive operator events associated with high level alarms, well shut-ins or a tank overfill situation. Oil losses to water storage tanks and diminished storage capacity due to excessive water levels in oil tanks are minimize through oil/water interface detection. It also provides validation of well production rates, off-lease transfers of produced water and tank gauging operations for oil custody transfer. Integrating this functionality into automated production management programs has proven to eliminate issues around well allocation, unaccounted for or lost production and production measurement compliance.