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Emerson Confidential 1
Best Practices For Making Allocation Measurements Using Separators and Multiphase Flowmeter Technology
Jody Overshiner
Emerson Confidential 2
Agenda
• Why Allocation Measurement is Important • Separator Challenges, Advantages / Disadvantages, Best Practices
• Multiphase Metering Challenges, Advantages / Disadvantages, Best Practices
• Conclusions
Emerson Confidential 3
Why Are Accurate Allocation Measurements Important?
Measurements may be used to pay royalties to landowners Risk of legal disputes when allocation and sales measurements don’t balance Poor separation efficiency causes lost gas to sales, flaring, metering problems, and frequent trips to the field Difficult to make reservoir and production management decisions with poor data
Inaccurate)Alloca-on)
Measurements)
Reduced)Revenue)
Emerson Confidential 4
Business Impacts of Poor Allocation Measurement
Up to 30% Differential from
allocation to sales measurement
$360K / year Lost gas to sales due to gas carry
under *
$3.2MM / year Oil lost to water tank due to poor
separation
* 120 wells | 150 BPD | $45 bbl oil | $2.10 gas price
Emerson Confidential 5
Methods of Allocation Measurement
Alternative method: Inline Multiphase metering
Use MPFM for periodic well testing replacing test separator and keep manifold and production separator
Use dedicated MPFM per well with production separator
Conventional method: Separator
• Periodic well test with test separator, manifold and production separator
• Dedicated separator per well
Production Separator
Local Storage
Bulk Separator
Local Storage
Test Separator
Dedicated Separators per Well
Bulk and Test Separators
Manifold
MPFM per Well
Bulk Separator
Centralized Processing & Storage
Manifold
Local Storage
Bulk Separator
Test MPFM and Bulk Separator
Manifold
Test MPFM
Allocation with MPFM at Wellhead to Centralized
Processing
Emerson Confidential 6
Separator Advantages
• Has to be done at some point anyway • Traditional technology
– Familiar • Easy to verify performance
– Can be verified interrogating functional components • Flexible and can fit in multiple places along the automaton spectrum.
– Tier 1 • Displacer level, regulator, pneumatic valves, Coriolis on oil / water, or low
power mag on water – Tier 2
• Level Controller / Radar level, regulator, electric actuated valve, Coriolis on oil / water, or low power mag
– Tier 3 • Radar level, electric actuated valve, regulator, Coriolis on oil and water,
RTU + separator control
Emerson Confidential 7
Separator Challenges
• Higher maintenance – Valves – Level instruments – Sand erosion – Mechanical flow meters
• Sizing – Changing production rates
• Poor separation can cause – Water bottoms, oil in water tanks – Challenges controlling vapors – Challenges managing inventory
• Higher CAPEX • Larger footprint required
Emerson Confidential 8
Separator Automation Best Practices
Coriolis Meter
Electric Actuator &
Dump Valve
Guided Wave Radar
RTU Platform
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 9
Separator Automation Best Practices
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 10
Separator Automation Best Practices
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 11
Separator Automation Best Practices
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 12
Separator Automation Best Practices
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 13
Separator Automation Best Practices
RTU Configured for Alerts
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 14
Separator Automation Best Practices
• Design your automation strategy to fit your needs
• Select smart flow, level, and pressure instruments to identify and control process upsets
• Utilize data to understand and optimize separator and well performance
• Monitor remotely and control with real time event reporting
Emerson Confidential 15
Methods of Allocation Measurement
Alternative method: Inline Multiphase metering
Use MPFM for periodic well testing replacing test separator and keep manifold and production separator
Use dedicated MPFM per well with production separator
Conventional method: Separator
• Periodic well test with test separator, manifold and production separator
• Dedicated separator per well
Production Separator
Local Storage
Bulk Separator
Local Storage
Test Separator
Dedicated Separators per Well
Bulk and Test Separators
Manifold
MPFM per Well
Bulk Separator
Centralized Processing & Storage
Manifold
Local Storage
Bulk Separator
Test MPFM and Bulk Separator
Manifold
Test MPFM
Allocation with MPFM at Wellhead to Centralized
Processing
Emerson Confidential 16
MPFM Measurement Principle
Fractions
Capacitance / conductance
Density
Velocities
Venturi
Time series / cross correlation Flow rates
Qoil Qwater Qgas
Emerson Confidential 17
Multiphase Advantages
• Sizing – Ability to scale for varying production rates
• Maintenance Free – No moving parts
• Small footprint • Smart diagnostics
– Ability to remotely monitor, calibrate, and tune • Some manufacturers have modular units
– Utilize individual technology components as required. • Reduction in HSE • Reduction in CAPEX and OPEX expenses
– Can be as much as a 50% reduction in CAPEX – Can replace test separator and manifold upstream of
Centralized Processing Facility • Real time continuous monitoring of all three
phases
Emerson Confidential 18
Multiphase Challenges
• Still have to separate • Limited knowledge with the technology
– Newer than separators – Initial tuning
• Requires accurate PVT – Necessary for accurate measurement, can differ per well
• Some require Gama components – May require additional training for compliance
• Perceived higher cost • Fiscal allocation
– Regulatory / Contractual Approvals • Validation via test separator or master meter
Emerson Confidential 20
Multiphase Best Practices
• Pay attention to manufacturer’s piping guidelines – Appropriate isolation valves and procedures
• Validate fluid densities • Have experienced personnel for installation and
setup • Calibrate on recommended intervals • Consider a fit for purpose modular design
Skid based MPFM
Modular MPFM Design
Emerson Confidential 21
Summary
• Separators – Makes sense on sites with local storage and you have to separate anyway – Easy to align with automation strategy – Leverage diagnostics to reduce allocation measurement uncertainty – Knowledgebase exits
• Multiphase – More cost effective for sites where you are only separating for allocation
measurement. – Smaller footprint and CAPEX and OPEX savings – Real-time measurement saves time during well testing (more frequent testing) – Modular design – Utilize manufacturer’s knowledgebase
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