21 – 22 February 2018 Houston, TX
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Multiphase Flow Meter Implementation, Verification and Use for Calibration of Virtual Metering in Kashagan
Project
Adilbek Mursaliyev
Beibit Akbayev
Overview of Kashagan
• The Kashagan field is located in the Kazakhstan sector of the Caspian Sea
• The reservoir lies some 4,200 meters below the shallow waters of the northern part of the Caspian Sea.
• The harsh offshore environment of the northern part of the Caspian Sea
• A unique combination of technical and supply chain complexity.
• One of the largest and most complex industrial projects.
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Overview of Kashagan
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Overview of Kashagan
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Overview of Kashagan
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• Satellite islands currently under operation: 2
• One hub island for oil and gas pre-processing
• Oil, gas and sulfur treatment plant in onshore
• One of the satellite islands’ wells equipped with individual MPFMs
Overview of MPFM technology in Kashagan
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• Model: Vx PhaseWatcher
• Venturi tube throat Diameter: 88 mm
• Barium-133 radioactive source and detector assembly
• Differential-pressure sensor
• Pressure sensor
• Temperature sensor.
Overview of MPFM technology in Kashagan
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Overview of MPFM technology in Kashagan
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Overview of MPFM technology in Kashagan
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Allocation scheme and well testing
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• Mass allocation
• Proportional Reconciliation
• 𝑅𝐹(𝑂𝑖𝑙) = 𝑖=0𝑛 𝑀𝑖
𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙
𝑀𝐴𝑐𝑡𝑢𝑎𝑙
• Where 𝑀𝑖𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 is estimated mass of i-th well and
𝑀𝐴𝑐𝑡𝑢𝑎𝑙 is measured mass at delivery point.
• 𝑀𝐴𝑐𝑡𝑢𝑎𝑙 is sum of oil measured by fiscal metering skid at custody transfer point and tank delta stock.
Allocation scheme and well testing
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M: multiphase flowO: treated liquid oil measured at custody transfer pointG: treated gas measured at custody transfer and internal usersS: Liquid Sulphur measurement
Allocation scheme and well testing
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• Hub island is equipped with one test separator
• Hub wells are routed to test line one by one
• One of the satellite islands have one MPFM shared by wells
• Another satellite island has individual MPFM for each well
Allocation scheme and well testing
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• Important to not penalize real time measurements
• Required to estimate well theoreticalsaccurately where there is not individual meter
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Upstream choke installation challenge
• Conditions at upstream the choke valve varies with the choke operation
• This leads to changes in PVT properties, e.g. shrinkage, density, etc. which impacts the phase and rate calculations;
• MPFM’s fluid model uses one single polynomial equation for PVT and fluid properties by default
• Challenge at and near bubble point. – The transition between above and below bubble
point smooth instead of sharp. This led to incorrect properties values used in the calculations.
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Upstream choke installation challenge
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Upstream choke installation challenge
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Solution
• Two separate PVT polynomial equations, one for above bubble point and the other for below bubble point.
• The auto switching algorithm developed in DCS:
• which sends Boolean signal (1 or 0 for below or above bubble point) to the flow computers depending on gas fraction and pressure/temperature values.
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Solution
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Solution
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Validation of MPFM
• Flow loop test
• restricted area of flow conditions
• accuracy of the reference instrumentation is correctly known
• Validation required because the MPFMs are operating within wide range of pressure conditions (between 120 – 500 barg)
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Validation of MPFM
• Validation tool built in excel with VBA
• Uses Peng-Robinson cubic equation of state.
• Used for phase fraction and total mass rate validation
• The deviation between calculated and measured total mass rate is within ±1%.
• The deviation for phase fraction is on average within ±5% absolute.
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Validation of MPFM
• Validation check by use of gas outlet measurements at production separators.
• Wells diverted to one production train for one month (segregation of the wells from the rest).
• Load ratios between the production trains from gas measurements at separators.
• The load ratios applied to total oil production at the outlet form the plant
• Compared against measured volume from MPFMs.
• The deviation around 3%.
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Validation of MPFM
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Validation of MPFM
• Additional test performed for 20 hours period:• production only from wells with MPFMs• and the produced and treated oil
accumulated at one tank in onshore. • The MPFM measured cumulative volume was
compared against accumulated oil in the tank. The deviation was 3% as well.
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Virtual flow metering and MPFM
• Availability of downhole gauges• The virtual flow metering concepts slowly
gaining “trust” from subsurface discipline engineers.
• One of the methods - Vertical Lift Performance (VLP) equation
•∆𝑃
∆𝐿= 𝜌𝑔 +
𝑓 𝜌 𝑣2
2 𝑑
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Virtual flow metering and MPFM
• Not all of the wells are equipped with individual MPFM
• Required to have alternative real time well rate estimation
• The VLP method tested on real time MPFM measurements
• After proving the concept, applied for other wells by tuning against test separator during planned well testing results
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Virtual flow metering and MPFM
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Virtual flow metering and MPFM
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Virtual flow metering and MPFM
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Future improvements
• The real-time MPFM measurements should be used for better understanding the following:
• Impact of slippage between phases to friction loss in the well production tubing;
• Impact of flow pattern to friction loss;• Impact of well curvature (deviation) to
friction loss.• Implement real time PVT and VLP calculations
on PI ACE™ engine.