Stringent Conditions Call for Precision Measures
Applying multiphase meters to hydrocarbon flow measurements
By Youssef F. Basrawi
Profits in the oil industry now are at all-time highs, but that doesn’t stop companies from trying to increase productivity from their processes. And one of the areas they can improve upon is in custody transfer. Unlike process conditions, custody transfer criteria have to comply with more stringent conditions.
Process conditions allow possible accuracy tolerances between 2% and 5%. Process data uses include internal material balance, leak detection, and loss control. Custody accuracy tolerances, however, need to be between 0.25-0.50% margins because financial and commodity exchange takes place at the point of custody, where you either gain or lose actual cash.
Operations, current research, field test studies, and viability of devices reveal better precision and higher accuracy in measuring volumetric throughputs for exports and domestic consumption. So major corporations and private instrumentation manufacturing companies in the hydrocarbon industry are evaluating current technologies for multiphase meters and water-in-crude detecting devices. In fact, Saudi Aramco is currently testing, applying, and evaluating oil-water sampling and monitoring devices.
Consider a two-phase multiphase meter, also called a water-cut meter or oil-in-water sampling device. The dielectric constant and conductivity of water are much higher than oil’s. This difference means the water-cut meter can measure the water content of oil and water mixtures. It measures the microwave dielectric properties of mixtures using the resonant cavity method. The density of a tube’s material affects its natural vibration frequency. By measuring the frequency, you can measure the density of the material.
A resonant cavity is a metal structure that confines an electric field and causes it to reflect back and forth within the cavity. If the wavelength of the electromagnetic waves equals one of the dimensions of the cavity, then the multiple reflecting waves constructively interfere and generate a standing wave, electric field resonance. If you fill a resonant cavity with a material, the resonant frequency of the cavity will shift by an amount directly related to the density of the material. The width of the resonant peak is related to the conductivity of the material in the cavity. Thus by measuring the resonant frequency and peak width, you measure the dielectric properties of a material in the cavity.
Improvements in electronics, temperature, and density compensation techniques have made continuous, online water-in-crude detection devices or monitors viable alternatives to out-dated sampling and testing techniques. By measuring the frequency of the resonant peak, you can measure the dielectric constant of the material in the cavity. The frequency measurement determines the dielectric constant accuracy. The resonant cavity method is a long-standing laboratory technique for accurately measuring the high-frequency dielectric constant of materials.
This method requires closed metal boxes that block flow of a continuous production stream of material. The full-cut oil-water meter shows sensors with a straight spool piece and two microwave connectors; one a transmitter and the other a receiver provide a resonant cavity through which fluids can flow continuously with little to no pressure loss. The pipe-like sensor serves as a cylindrical waveguide within which transmitted electromagnetic waves will propagate freely, permeating the whole cross-section. Metal plates at either side confine the waves within the measurement section, making a resonant cavity.
The capacitance, energy absorption, microwave, and sub-megahertz technologies are all based on measuring the dielectric constants of a liquid due to changes in water content. Another emerging technology is based on measuring the absorption rate of infrared energy by water and hydrocarbon molecules.
In various water-in-crude monitoring devices, we base measurement of water content on measurement of dielectric constants (degree of conductivity) of the liquid due to changes in water content.
You can use water-in-crude detection devices in well testing, production, gathering systems for material balance, and inventory accounting and allocation purposes. More accurate water data at well testing would result in more accurate allocation. Better water determination at the well site and at gathering systems results in better and more efficient management of a field. Another big benefit is monitoring the operation of water separators to maximize separation while also maximizing throughput. Cost savings could be tremendous. You can also apply water-in-crude detection devices in process flow for accurate real-time feedstock and process water-content control in refineries. You can automatically trend water content in a system in real time and identify upset potentials before they happen, avoiding damage to processes and equipment.
By applying water-in-crude detection devices you could automatically operate the whole custody transfer process of water sampling. You’d no longer have to pull samples, transport them to a laboratory, or analyze and manually transcribe data. This would minimize human error, reduce maintenance costs, and automate billing, applying it in real time. You could also quickly correct out-of-tolerance situations before they reach unsatisfactory levels.
Saudi Aramco is in the process of testing, applying, and evaluating water-in-crude monitoring devices. One gas-oil separation plant (GOSP) tested a water-in-crude instrument as an economical, compact, and accurate method to measure oil-well production rates. The test also determined the amount of water and gas mixtures present in the wells used to extract crude from the ground and GOSP. When wells mature, their internal pressure, thrusting the crude and gas to the surface, begins to diminish. Testers inject water, and sometimes mud, into the well to force the crude and all the injected contaminants out. We call this primary, secondary, and tertiary well recovery. In the U.S., wells are mature and require secondary and tertiary recovery.
For well recovery and gas-oil separation operations, the accuracy criteria is between ± 5-10% of instrument reading as compared to testing reference. For financial calendar (FISCAL) measurements, the accuracy must be ± 0.25% or better. Major oil companies participate in joint industrial partnering and field technical planning with each other for testing and evaluating new technologies in the hydrocarbon industry. Once testers have accepted a test and evaluated field data, they make a joint recommendation to the International Petroleum Institutes in the U.S. and worldwide to adopt such new technologies. We tested the multiphase flowmeter (MPFM) for 35 days, during which we used GOSP’s test trap as a reference measurement to evaluate the meter’s accuracy. We chose 36 wells for testing and conducted 60 tests to check the MPFM and GOSP’s test trap consistency.
Oil pros and cons
The existing conventional crude oil sampling systems sit outside the pipeline with the only interface with flowing liquid via a thin sample probe device. The grab sample usually travels to the sample container causing fluid dead legs in the sample lines. The disadvantage is the conventional sampling procedure occurs in several steps, consuming time and requiring constant maintenance due to the many intermediate parts of the equipment. Installed water-cut meter in line and in direct contact with the process fluid gives real-time continuous water contents in the crude line by measuring dielectric constants and conductivity of water/crude interface. The automatically temperature-compensated meter design allows for minimum pressure drop. It’s easy to field calibrate for different process fluids and requires minimum maintenance. Operations in well testing and production are some of the many currently being tested and evaluated by major corporations and private instrumentation manufacturing companies in the hydrocarbon industry.
Water-cut meters measure the microwave dielectric properties of mixtures using the resonant cavity method. The natural vibration frequency of a tube is affected by the density of a material in it. Capacitance, energy absorption, microwave, and sub-megahertz technologies are all based on measuring the dielectric constants of a liquid due to changes in water content. Emerging technologies are based on measuring the absorption rate of infrared energy by water and hydrocarbon molecules. You can install the oil-water monitoring devices in line and in direct contact with the process fluid. They give real-time continuous water contents in the crude line by measuring dielectric constants and conductivity of water/crude interface.
The automatically temperature compensated meter design for minimum pressure drop is easily field calibrated for different process fluids and requires minimum maintenance. It requires a line mixer upstream and does not give sediment quantities.
Based on 29 trial tests conducted on the MPFM at the GOSP, the meter showed good repeatability for an acceptable 10% accuracy measurement as compared to the reference measurement (test trap). The maximum operating range of the MPFM we used was 4,500 BPD as compared to that of the reference measure 7,500 BPD. This shows you would need to use the appropriate size meter to obtain better accuracy, especially at the higher flow ranges.
For custody transfer required accuracy must be within +0.25%. Today’s instruments are capable of measuring the full range (0-100%) of water to within +0.05%. This is as good as the repeatability of laboratory tests used for determining the water content in custody transfer applications. It has an accuracy of ±0.1% of full scale for measurement temperature range of 0-120°C (-32 to 250°F), 0.080% deviation for 1.210% water-in-crude and 0.400% for 5.485% water-in-crude using the ASS as reference, 0.000% deviation for 0.510% water-in-crude, and 0.410% deviation for 4.880% water-in-crude using the MSS as reference.
In relation to Saudi Aramco’s evaluation of oil-water sampling and monitoring devices, we are balloting a new draft Chapter 8.2 “X” on automatic sampling systems for online water-in-crude monitors to include in the American Petroleum Institute Manual of Petroleum Measurement Standards chapters on sampling systems and determination of sediment and water in crude. Once we’ve conducted conclusive tests and pass the oil-water monitors as alternate water-in-crude measuring devices (and if official governing authorities find them acceptable), we would not require collection of sample and lab analysis. The sampling systems for royalty and custody measurement will implement this technology.
About the Author
Youssef F. Basrawi is an engineering specialist in the Flow Measurements Process and Control Systems Department at Saudi Arabian Oil Co. in Dhahran, Saudi Arabia.
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