Orifice plate meter field performance: Formulation and validation in multiphase flow conditions

• We implemented a multi-rate test in two wells in an oil field.
• We used an orifice plate model to estimate oil, gas and water flow rates.
• We compare results with simultaneous experimental data coming from separator test.
• Oil, gas and water volumetric flow rate deviations (CV RMSD) were below 3.52%.
• Metering methodology is used for real-time monitoring at Urucu oil field.

The performance of orifice plates in real-time monitoring of oil, gas and water standard flow rates was investigated. To this end, a multi-rate test was implemented in two production wells routed individually to a test separator in field operational conditions. The well flow rate was varied in steps by changing the choke opening.The ranges of fluid properties and flow conditions achieved during the experiment were: wellhead pressure from 9073 kPa to 13,278 kPa, wellhead temperature from 47.8 °C to 53.5 °C, downstream choke pressure from 6770 kPa to 7913 kPa, downstream choke temperature from 41.6 °C to 49.1 °C, gas–oil-ratio from 1144Sm3/Sm3 to 2068Sm3/Sm3, water-cut from 4.64% to 58.35%, standard oil specific gravity from 0.7988 to 0.8058, standard gas specific gravity from 0.7340 to 0.7550, standard oil flow rate from 46.86Sm3/d to 266.65Sm3/d, standard gas flow rate from 62.68×103Sm3/d to 296.65×103Sm3/d, standard water flow rate from 18.06m3/d to 159.33m3/d.The wells tested showed a different dynamic behavior: while well #2 did not vary significantly the stream composition with flow rate, well #1 produced under gas coning, a near well-reservoir phenomenon that governs the contribution of the reservoir gas-cap to the total stream composition.The multi-rate tests generated two data sets with 1424 flow conditions through two flange-tap orifice plates installed upstream (wellhead) and downstream of a cage choke valve. The ranges of orifice variables were: orifice diameter from 0.03479 m to 0.0430 m, beta factor from 0.4946 to 0.6507, differential pressure from 15 kPa to 187 kPa.The virtual metering system presented in Paz et al. (2010) was used to correlate the experimental data. The associated model, suitable for differential pressure measuring devices, includes effects such as flow concentration and slip (through Chisholm’s correlation), generalizing the mass flow rate versus pressure drop relationship for multiphase flow. The total mass flow rate depends on a set of variables evaluated at metering conditions: density and viscosity of the liquid and gas phase, mass quality, pressure drop across the flow meter and geometry (contraction area and beta factor).The determination of the fluid properties at metering conditions was made by using black-oil correlations. These correlations are based on a set of input variables at standard condition that characterizes the stream composition such as gas–oil ratio, water–oil ratio and specific gravities of each phase.A comparison was made between the multiphase flow rates predicted by the model and the ones simultaneously measured at the test separators. The oil, gas and water standard volumetric flow rate deviations (coefficients of variation of the root mean square deviations) were below 3.52%3.52%.It was theoretically demonstrated and experimentally verified that a systematic error exists when the homogeneous model (equal phase velocities) is considered in the formulation, resulting in a flow rate underestimation. When the homogeneous model was used to correlate the data, this effect increased the deviation up to 10.5%10.5%.Flow pattern at the wellhead was characterized as intermittent and annular-mist. Lockhart–Martinelli parameter varied from 0.362 to 0.836; despite of the experimental data being beyond the wet gas region, the multi-rate tests showed that Chisholm’s over-reading can be successfully extrapolated to these range.