Multiphase MixMeter. MixMeter specification. System Specification. Introduction

Transcription

1 System Specification Multiphase MixMeter Introduction The MixMeter is unique in applying proper homogenization techniques to multiphase measurement. In so doing the MixMeter avoids the requirement for computer slip modeling and does not need particular up or downstream piping configurations. The MixMeter system comprises no moving parts and is not susceptible to major changes in multiphase flow compositions. Tried and trusted technology MixMeter operates on the principle of equalizing the slip velocity and homogenizing the flow to ensure measurement accuracy. The principle of the is founded upon established measurement techniques. Simplicity MixMeter is designed to be simple to use and easy to maintain. Field equipment is kept to a minimum with all data processing performed by the safe area flow computer. Reliability Reliability of MixMeter is inherent in its simplicity. The only uses proven and accepted offshore technology to guarantee performance. The has been designed to incorporate the minimum of components to ensure reliability. The field equipment comprises a gamma densito, standard pressure and temperature transmitters and a single processing board. All data is transferred to a remote PC via RS485. Calibration MixMeter is simple to calibrate and easy to verify. Gas/Air, Oil and Water calibration points are collected by filling the tube with the individual component and measuring the absorption coefficients for each of the two measured energy levels. The density / PVT data curves are from API 2540 for the liquid and AGA 8 / NX 19 for the gas, which are pre-programmed within the computer prior to dispatch. Minimal calibration verification is required once the is installed. All of the calibration data is stored within the computer. Simple to verify calibration The MixMeter measurement performance can be verified after installation by purging the of liquids and performing a verification test. Verification determines empty pipe constants and compares these with previous verification values. Verification can also used to detect a build up of scale or wax in the. MixMeter specification

2 Compact The is designed to be compact, approx 1500mm long x 1000mm wide x 1500mm high, estimated dry weight 800kg. Flow regime independent MixMeter is completely impervious to changes in flow regime and does not rely upon any regime modeling techniques for measurement Phase independent - MixMeter operation is independent of whether the flow is oil or water continuous. Operating Description The MixMeter is a second-generation multiphase that provides a compact solution and can operate over a full range of water-cut and gas volume fractions. The MixMeter operates on the principle of axial flow regime stabilisation prior to measurements being taken. The use of a patented mixer design equalises the velocity of the phases and enables the MixMeter to accurately measure the volume fractions without using complex flow-regime modelling techniques. The mixer provides effective isolation from installation effects eliminating measurement bias. The differential pressure measured across the mixer provides a simple and accurate method to determine bulk flow rate. This, coupled to the volume fraction generated by the measurement unit, provides net oil, gas and water rates. The measurement unit comprises a dual energy gamma Densito using two energy levels from a single source impinging on the same detector. An industry accepted isotope is used, being chosen to eliminate errors at the edges of the operating envelope. The densito has a short measurement interval ensuring that the MixMeter is not biased by slug flow. The dual beam Densito provides primary outputs in terms of mass fractions that are combined with PVT data and rate measurements to give volumetric flow rates. The MixMeter calibration is carried out using chemical analysis of the produced fluids. These calibration coefficients are determined from composition data or by measurement of the fluid characteristics. The operator interface is via a remote PC using a Windows operating system. All software upgrades can be carried out using this PC. Maintenance of the system is simplified by using standard transmitters throughout the system. Detailed Equipment Breakdown 1.1.1) MixMeter Multiphase Meter The field equipment would consist of the following. 1 off ANSI 900 RF MixMeter Multiphase Meter including all wiring and cabling to electronics enclosure The MixMeter is a compact, in-line multiphase that operates over a full range of watercut and gas volume fractions. 1 off Stainless Steel MixMeter spool Complete with ANSI 900 RF flanged connections 1 off Patented Homogenizing Element Welded within the 4 spool. Designed to homogenize the flow and provide a differential pressure. 1 off Rosemount Series 3144P SMART Temperature Transmitter with LCD, complete with 4 wire PT100 RTD and flanged 1 1/2 ANSI 900# RF Stainless Steel Thermowell. Certified EEx d. 2 off Rosemount Series 3051CD SMART Differential Pressure Transmitter with LCD, Hastelloy C276 Connection and Sensor Materials, mounted across a 5-valve St.Stl. manifold. The manifold would be isolated from the MixMeter spool via two off 3-piece isolation ball valves Stainless Steel body with St.Stl. Ball. Certified EEx d.

3 1 off Rosemount Series 3051CG SMART Pressure Transmitter with LCD, Hastelloy C276 Connection and Sensor Materials, mounted on a 2-valve St.Stl. manifold. The manifold would be isolated from the MixMeter spool via a 3-piece isolation ball valve, Stainless Steel body with St.Stl. Ball and Trim. The pressure transmitter will measure the static pressure at the outlet to the measuring cell. Certified EEx d. 1 off Dual Energy Density Meter and Source Complete with temperature stabilization system. The temperature stabilization system incorporates a PTFE insulation spacer, and a pumped coolant loop operating at 2 litre/minute. Should a site water supply be available the pump would not be required. The temperature stabilization system is designed to maintain a stable temperature at the detector, and avoid any external effects upon the measurement accuracy. The source will be Caesium/Barium in an IP 3204/3205 capsule mounted in a 810DP Type A approved source holder which is mounted on the MixMeter. The detector is a Synetics PRI 116 dual energy density gauge. 1 off Simple IMON interface board Mounted in an EEx d enclosure with a single interface to the flow computer 1 off Set of 316 Stainless Steel dual ferrule fittings 1 off Cable, Cable Glands and Shrouds 1 off Carbon Steel support Frame. 2 off 1 ANSI 900# RF Drain & Calibration Isolation Ball Valves Isolation Ball Valve, Stainless Steel body and internals, fire safe and anti-static ) 1 off MixMeter Safe Area Flow Computer & HMI A stand alone desk mounted PC will be supplied for the MixMeter, an optional rack mounted PC is available. The PC must be installed in a customer temperature controlled room classified as safe area. The MixMeter flow computer is a PC running a Windows operating system. The flow computer is connected to the field equipment via a single interface that transfers raw data from the field equipment to the flow computer. Complete with HMI screen, keyboard and mouse to provide visual interface with the MixMeter flow computer. The MixMeter software uses patented processing algorithms to process the data that is then displayed and reported. MixMeter software can store the fluid calibrations for a large number of oil wells. This allows the to be operated on a range of oil wells containing fluids of different properties simply by loading the correct fluid calibrations. Each set of fluid calibrations are saved with a specific well name to avoid errors. 1.2) MixMeter Operation Summary 1.2.1) Operating modes MixMeter has two calibration/operating modes that would be used in a field environment: Variable Phase/Variable Density Fixed Phase/Variable Density (no change of phase occurs) Variable density/variable phase will give the highest accuracy provided calibration data is available to operate in this mode ) Variable density/variable Phase Calibration points are as follows: Pipe Empty 100% Hydrocarbon 100% produced salinity

4 Calibration points are calculated by MixMeter from the data input in the chemical analysis screen. In this mode MixMeter also needs the following tables: Oil density in relation to temperature and Water density in relation to temperature and pressure across the operating range of the Gas density in relation to temperature and Hydrocarbon mass fraction in relation to temperature and pressure across the operating range of the If density data is unavailable then standard API look-up tables can be used. MixMeter continually measures the transmission ratios of the two energy levels (32KeV and 661KeV) through the multiphase flow every 10m/s. The transmission ratios are the primary measure of the mass fractions of hydrocarbon and water. The hydrocarbon mass fraction table is then used to determine the mass fraction of the hydrocarbon that is oil and gas at the process pressure and temperature. The oil, water and gas mass fractions are converted to volumetric fractions using the oil, water and gas density tables. Either the volumetric or mass fractions can be used with the DP to determine individual phase mass or volumetric flow rates. The DP equation is as follows: Ap = k U 2 EL k = Resistance factor of mixer U = Total superficial velocity EL = Liquid fraction 1.2.3) Variable density/fixed phase Calibration points are as follows: Pipe Empty 100% Gas 100% Hydrocarbon 100% produced salinity Calibration points can be calculated by MixMeter from the data input in the chemical analysis screen or directly measured from the fluids. In this mode MixMeter also needs the following tables: Oil density in relation to temperature and Water density in relation to temperature and pressure across the operating range of the Gas density in relation to temperature and If density data is unavailable then standard API look-up tables can be used. MixMeter continually measures the transmission ratios of the two energy levels (32KeV and 661Kev) through the multiphase flow every 10m/s. In this mode the transmission ratios are the primary measure of the volumetric fractions of oil and water determined using the density tables. Either the volumetric phase fractions can be used with the DP to determine individual or volumetric flow rates. The DP equation is as follows: Ap = k U 2 EL k = Resistance factor of mixer U = Total superficial velocity EL = Liquid fraction Mass flow rates are determined from the volumetric flow rates and the density tables.

5 Changes in process variables Results can be re-processed for changes in calibration data using the MixMeter re-process feature. MixMeter Calibration Summary 1.2.4) Factory Calibration The transmitters, density gauge are all calibrated at the factory prior to shipment and the source decay is set to provide a reference for decay calculations for the source half-life (typically 30 years) 1.2.5) Site Calibration Once the is installed the factory calibration of the transmitters should be checked and a density gauge calibration check performed on the when the pipe is empty to check the 0 point calibration ) Individual Well/Fluid Calibration For optimum results, MixMeter needs calibrating for the fluids for each oil well (if they differ), the information is input directly into the flow computer software using a simple input screen. The following tables/polynomials are required to calibrate the : Absorption co-efficient of the fluids PVT data: Oil density in relation to pressure and temperature Gas density in relation to pressure and temperature Hydrocarbon gas mass fraction in relation to pressure and temperature (phase transfer) The salinity of the water (total dissolved salts) How this information is derived depends on the availability of data from the customer and the selected operating mode of the. MixMeter can be operated in three modes. The calibration requirements and brief description of each operating mode is below: ) Fixed density, fixed phase mode This is used primarily for testing the at facilities where no change of state occurs between phases (i.e. gas turning to liquid under pressure) such as occurs at many of the multiphase test rigs where the gas in not a hydrocarbon. In this mode the calibration data can be derived in the following manner: Co-efficient can be determined by direct measurement of the liquids in the (empty, full of oil, full of water) or calculated by the from a chemical analysis PVT data is not required Salinity must be input from an analysis ) Variable density, fixed phase mode This mode is used when there is likely to be little or no phase transfer with pressure and temperature or the operator does not have that information available. In this mode the calibration data can be derived in the following manner: Co-efficient can be determined by direct measurement of the liquids in the (empty, full of oil, full of water) or calculated by the from a chemical analysis In this mode only the density PVT data is required Oil density in relation to pressure and Gas density in relation to pressure and No phase transfer PVT data is required Salinity must be input from an analysis

6 ) Variable density, variable phase mode This mode is full operating mode with all calibration points and offers the best accuracy. It corrects for changes in both density and state (liquid and gas) in the calibrated envelope of the. In this mode the calibration data can be derived in the following manner: Co-efficient are calculated by the from a chemical analysis In this mode all PVT data is required Oil density in relation to pressure and Gas density in relation to pressure and Hydrocarbon gas mass fraction in relation to pressure and temperature from an analysis of the fluids (such as provided by Core Labs etc.) Salinity must be input from an analysis Once operating mode is selected and the calibrated for each well the calibrations are automatically loaded when the configuration file for that well is loaded prior to well testing ) Calibration Check In order to check the 0 calibration point of the it is recommended that that MixMeter be emptied and a 0 point calibration performed on a scheduled basis (such as every 6-12 months) with the filled with a known gas. The ideal gas is Nitrogen but in a field environment this is often not available in sufficient quantity to achieve the necessary purging velocity through the. In this case it is possible to use another known gas, such as dry field gas from a separator to purge and verify the calibration. The measurement is then corrected for the gas composition and used verify the calibration. Prior to the verification, MixMeter must be purged with the gas at a velocity greater than 15m/s to remove trace liquid from the pipe walls. A 0 point verification is performed by draining the, purging the internals for liquid residue and then filling it with the known gas at atmospheric pressure. After the verification the gas can be vented to a flare stack and the readied for measurement. (In applications with high viscosity crude the MixMeter may need heating or a solvent purge prior calibration). Jiskoot Limited - UK Goods Station Road, Tunbridge Wells, Kent TN1 2DJ Tel: +44 (0) Fax: +44 (0) sales@jiskoot.com Jiskoot Incorporated - USA Bammel N, Houston #110, Houston,Texas, Tel: Fax: sales@usa.jiskoot.com These are standard design specifications. We operate a policy of continuous development and the information on this sheet may be updated without notice.