Ttyjfyk

A multiphase flow meter is a device used to measure the individual phase flow rates of constituent phases in a given flow (for example in oil and gas industry) where oil, water and gas mixtures are initially co-mingled together during the oil production processes.

Background

Knowledge of the individual fluid flow rates of a producing oil well is required to facilitate reservoir management, field development, operational control, flow assurance and production allocation.^[1]

Conventional Solutions

Conventional solutions concerning two- and three-phase metering systems require expensive and cumbersome test separators, with associated high maintenance, and field personnel intervention. These conventional solutions do not lend themselves to continuous automated monitoring or metering. Moreover, with diminishing oil resources, oil companies are now frequently confronted with the need to recover hydrocarbons from marginally economical reservoirs.^[2]
In order to ensure economic viability of these accumulations, the wells may have to be completed subsea, or crude oil from several wells sent to a common production facility with excess processing capacity. The economic constraints on such developments do not lend themselves to the continued deployment of three-phase separators as the primary measurement devices. Consequently, viable alternatives to three-phase separators are essential. Industry’s response is the multiphase flow meter (MPFM).

Historical Development

The oil and gas industry began to be interested in developing MPFMs in the early 1980s, as measurement technology improved, and wellhead separators were costly. Depleting oil reserves, (More water and gas in the produced oil) along with smaller, deeper wells with higher water contents, saw the advent of increasingly frequent occurrences of multiphase flow where the single-phase meters were unable to provide accurate answers. After a lengthy gestation period, MPFMs capable of performing the required measurements became commercially available. Much of the early research was done at the Christian Michelsen research center in Bergen, Norway,^[3] and this work spawned a number of spin off companies in Norway leading to the Roxar / Emerson, Schlumberger, Framo, and MPM meters. ENI and Shell supported the development in Italy of the Pietro Fiorentini meter. Haimo introduced a meter with partial separation, making accurate measurement simpler, but at the expense of a physically larger device. Norway has remained a technology center for MPFM with the Norwegian Society for Oil and Gas Measurement (NFOGM) providing an academic and educational role.^[4] Since 1994, MPFM installation numbers have steadily increased as technology in the field has advanced, with substantial growth witnessed from 1999 onwards.^[5] A recent study estimated that there were approximately 2,700 MPFM applications including field allocation, production optimisation and mobile well testing in 2006.^[6]

A number of factors have instigated the recent rapid uptake of multiphase measurement technology: improved meter performances, decreases in meter costs, more compact meters enabling deployment of mobile systems, the need for sub sea metering, increases in oil prices and a wider assortment of operators. As the initial interest in multiphase flow metering came from the offshore industry, most of the multiphase metering activity was concentrated in the North Sea. However, the present distribution of multiphase flow meters is much more diverse.

Most modern meters combine a venturi flow rate meter, with a gamma densitometer, and some meters have additional measurements for water salinity. The meter measures the flow rates at line pressures, which are typically orders of magnitude greater than atmospheric pressure, but the meter must report the oil and gas volumes at standard (atmospheric) pressure and temperature. The meter must thus know the Pressure / Volume / Temperature properties of the oil, to add to the measured gas rate at line pressure the additional gas that would be liberated from the oil at atmospheric pressure, and also know the loss in oil volume from the release of that gas in conversion to standard conditions. With co-mingled flow from oil zones with differing PVT response, and different water salinities and hence densities, this PVT uncertainty may be the largest source of error in the measurement.

The introduction of the multi port selector valve (MSV) also facilitated the automation of the use of MPFM's, but this can also be achieved with conventional valving designs for well tests. MSV's are particularly suitable for onshore pad drilling,and where many nearby wells have similar pressures, and allow MPFM's to be shared between groups of wells. Sub Sea meters typically use conventional sub sea valve designs, to ensure maintainability.

Advance Test Separator

Alternatives to MPFM's include automated advance test separators. They separate gas from liquid for 2 Phase measurement. The main principle is to effectively separate the free gas from the liquid phase and to measure each phase independently, but with more automation than a conventional separator. With complete separation, the measurement equipment used in each phase can be utilized to their maximum effectiveness and potential. The separation of gas and liquid occurs in 2 stages. Stage 1, the liquid enters a vertical pipe at a downward tangential angle creating a cyclonic action in the pipe. This cyclonic action pushes the liquid towards the pipe wall and enables the majority of the gas to release to the center of the pipe and travel up to the gas run. The liquid with some remaining gas is carried into a secondary stage of separation.

In the 2nd stage of separation, the liquid with remaining gas flows along a horizontal section of pipe. The liquid level in the horizontal pipe is controlled in the middle of the pipe. The liquid level is controlled by a liquid level sensor in the horizontal pipe and a control valve in the gas run. As the liquid level rises in the horizontal pipe, the level sensor sends a signal to the control valve and which begins to pinch shut to create some slight back pressure to push the liquid level down. Conversely, as liquid level goes goes down, the control valve beings to open to relieve pressure to allow the liquid level to rise. In essence, the control valve modulates to maintain the liquid level in the middle of the horizontal pipe. With a large gas/liquid interface area, thin gas-bearing emulsion layer and quiescent flow in the horizontal pipe, all contribute to the final removal of free gas bubbles from the liquid stream. All of the free gas removed in the horizontal section joins the gas run through a connecting run and is measured in the gas leg. The liquid, now free of gas drops to a liquid run for measurement.

In the liquid run, Coriolis metering technology is typically employed for flow measurement. Water cut can be determined by either Net Oil Computer (density method) or through a separate water cut meter. The gas is typically measured with ultrasonic, vortex, or Coriolis technology. All technologies used in the Accuflow are already currently practiced and approved by all major oil companies. After measurement the gas and liquid streams are recombined and returned to the production line.

Because the multiphase stream is completely separated into liquid and gas stream prior to measurement, the systems can operate in all flow regimes. It is applicable to full range of gas fraction.^[7]

Unconventional Solutions - SONAR Multiphase Measurement

Measurement and interpretation of 2 and 3 phase multiphase flow can also be achieved by using alternative flow measurement technologies such as SONAR. SONAR meters apply the principles of underwater acoustics to measure flow regimes and; can be clamped on to wellheads and flow lines to measure the bulk (mean) fluid velocity of the total mixture which is then post-processed and analyzed along with wellbore compositional information and process conditions to infer the flow rates of each individual phase. This approached can be used in various applications such as black oil, gas condensate and wet gas.

Market

Industry experts have forecast that MPFMs will become feasible on an installation per well basis when their capital cost falls to around US$40,000 – US$60,000. The cost of MPFMs today remains in the range of US$100,000 – US$500,000 (varying with onshore/offshore, topside/subsea, the physical dimensions of the meter and the number of units ordered). Installation of these MPFMs can cost up to 25% of the hardware cost and associated operating costs are estimated at between US$20,000 and $40,000 per year.^[8]

A number of novel multiphase metering techniques, employing a variety of technologies, have been developed which eliminate the need for three-phase separator deployment. These MPFMs offer substantial economic and operating advantages over their phase separating predecessor. Nevertheless, it is still widely recognised that no single MPFM on the market can meet all multiphase metering requirements.^[9]

References

External links

• NFOGM 2005 Handbook on Multiphase Flow Metering


• Overview of MPFM Technology by Lex Scheers - 2008 but still valid