SPE Member

Summary

In many unprocessed natural gas measurement locations between wellheads and process plants, water and condensate are entrained with the gas flow. Flow measurement at these locations is used for reservoir management, monitoring, control, production allocation, and custody transfer. The accuracy of wet gas metering is of great importance, especially allocation and custody meters, because of the monetary value of the large volume of unprocessed natural gas being transferred daily.

This paper presents the effect of orifice meter orientation, installed in horizontal, upflow, and downflow positions, on the accuracy of flow measurement. Tests were conducted at the Chevron Petroleum Technology Company's Air Flow Facility in La Habra, California. Two-inch orifice meters with three different orifice/pipe diameter ratios (beta ratios) were selected for testing. Air and water were used as flowing fluid, and they were controlled and measured by sonic nozzles and turbine meter, respectively.

The effects of liquid entrainment on metering error are characterized at each operating position. The results of this study indicated liquid entrainment in orifice meters always contributes lower gas flow rate measurement, up to -2% at vertical upflow position. In order to minimize metering errors in wet gas flow measurement, an orifice meter should be installed in a horizontal position with a mid-range beta ratio.

Currently, there is no acceptable correlation to adjust low liquid entrainment in orifice metering flow. To maintain metering accuracy, the author recommends improving system design to avoid liquid entrainment in orifice meters. In addition, unaccountable liquid condensate accumulation in the meters is a potential loss of revenue.

Introduction

The current orifice meter standard for natural gas flow measurement is the American National Standard Institute ANSI/API 2530 (American Gas Association AGA 3). This standard applies to homogeneous, single-phase, and steady-state flow. The orifice discharge coefficients were developed in controlled conditions with a flow having these properties.

In oil and gas production, many gas measurement points are located at the wellhead, gathering location, plant inlet, and offshore platform. Natural gas flowing in these conditions consists of heavy hydrocarbon components that will condense when changes in flowing pressure and temperature occur. In addition, small amounts of liquid carryover from a separator to the gas pipe line are also common. Under these conditions, the flowing fluid is no longer homogeneous and single phase. The gas- liquid quality is typically in the range of 0.99-1.0. When applying ANSI/API 2530 orifice flow equations to calculate unprocessed gas with small amounts of liquid, the basic assumptions for the equations are violated. Therefore, measurement errors are expected to be introduced in these conditions. Chevron's field calibration data obtained with unprocessed gas show that orifice meters underpredict the gas flow rate in the range of 0.5 to 2.5%.

There are several published correlations on two-phase flow measurement with orifices. The commonly mentioned works are Murdock, James, and Lin. For gas-liquid flow measurement in orifice meters, the total flow rate and the quality are the parameters to be determined. Most of these correlations were derived from homogeneous and separated flow models with known liquid/gas ratios. The basic assumptions of these models were developed for higher liquid flow rates than are normally present in unprocessed gas flows. It is not certain whether these models are valid for high quality flow conditions. Currently, there are no correlations developed to correct the gas flow equation at a lower liquid loading.

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