A Methodology for Efficient Verification of Subsea Multiphase Meters used in Fiscal Allocation

Transcription

1 A Methodology for Efficient Verification of Subsea Multiphase Meters used in Fiscal Allocation Richard Streeton FMC Technologies Ian Bowling - Chevron February 2016 Houston, TX

2 Contents The MPM Meter Technology Jack & St.Malo Field and Meter Configuration In-situ Verification and PVT Uncertainty Subsea Oil In-situ Measurements Jack & St.Malo Meter Verification Conclusions 2

3 The MPM Meter Technology Multiphase & Wetgas (Dual Mode) Venturi Total mass flow 3D Broadband tomographic measurement Phase fractions of oil, gas and water Gas-volume-fraction (GVF) Water-liquid-ratio (WLR) Liquid/gas distribution within the pipe Gamma densitometer mixture density Salinity probe water salinity Field configuration parameters Oil/gas densities Oil/gas viscosities Surface tension 3

4 Jack & St.Malo Meters The JSM field installation includes 21 (11 phase one) subsea 3 meters with 0.7 beta ratio operating in multiphase mode 7 topside 7 meters with 0.7 beta ratio, operating in Dual Mode (multiphase & wetgas) with salinity measurement Start-up 1 st Dec 2014 Flow loop testing at K-lab performed as part of delivery

5 Jack & St. Malo Layout A complete allocation system with 3-phase flow rate measurements at different locations using different measurement methods

6 Fiscal Allocation Subsea MPM meters on each well must be consistent with topside MPM meters verified continuously test separator verified periodically the export meters verified continuously PVT conversions MPM meters make measurements at their operating conditions meters may lack information about the downstream process large P&T differences between various measurements fluid conversions handled by Chevron externally to the meters 6

7 Multiphase Meter Validation Procedure Established by Chevron with the support of MPM prior to the start of production. Used in supporting documentation to regulator Description of monthly verification procedures to be carried out by MPM through a remote connection In the event of a greater than expected test difference: Step-by-step procedure for flow line testing of a single subsea meter versus topside (not used as yet)

8 Uncertainty Breakdown Meter Configuration Conversion Technology, Flow Models, software, Flow loop testing PVT quality, EoS models, comingling, reservoir changes, EoR PVT quality, production process, comingling Each uncertainty element must be addressed in setting acceptance criteria

9 Sources of Configuration Uncertainty PVT Sampling Process Lab Analysis Co-mingled Production Software Modelling Well Inflow Performance PVT Table Interpolation Choice of Equation of State (EoS) Natural Changes in Composition Enhanced Oil Recovery

10 Setting Verification Acceptance Criteria What is a reasonable expectation for fiscal allocation? MPFM plus Reference uncertainty should be included Configuration of single-phase properties Conversion to reference conditions e.g. standard, topside separator Verification on Total HC mass is less susceptible to external uncertainties

11 %Uncertainty Example Liquid Flowrate Uncertainty Regulator Requirement MPFM MPFM, Reference MPFM, Reference, PVT MPFM, Reference, PVT, Conversion MPFM, Reference, PVT, Complex Process Conversion In many cases, the MPFM uncertainty may be the smallest Note that PVT configuration and conversion uncertainties are systematic

12 In-situ Verification Perform monthly in-situ verification on all subsea and topside MPM meters Verification of meter integrity Verification of field configuration (PVT) 12

13 In-situ verification Oil In-situ The oil in-situ is particularly useful in the below applications: Fiscal measurements where the regulator requires frequent verification of the MPM meter measurement Co-mingled production where the true oil density may not be well known Subsea projects where the MPM meter is installed at wellhead conditions such that the hydrocarbons flow in a single (oil) phase.

14 Gamma Density Measurement Single high-energy gamma of 662 kev is a true density measurement Mass absorption for oil and gas is almost constant Able to measure density directly N No* e x N : Gamma Photon Count Rate No : Empty Pipe Calibration Value μ : Mass attenuation coefficient ρ : Density x : Pipe diameter

15 Oil In-situ Verification

16 Oil In-situ Verification 1 Well shut-in (routine) Chevron trend/export density and P&T data to MPM 2 Pure oil detected inside the meter? P & T within reasonable limits of operating conditions? 3 All valid data captured and added to a database Adjustment when difference is seen to be significant 4 Flowing data first recalculated to understand the impact Upload new table to meter

17 Oil In-situ Verification Differences in total hydrocarbon mass between subsea and topside Oil in-situ verification carried out over a number of months Small data sets accumulated to obtain an average oil density correction

18 Oil In-situ Verification Accumulated results over longer periods of time provide a better correction than a single point

19 Oil In-situ Verification One correction applied for Jack and another for St.Malo fluids Oil in-situ correction applied Agreement Subsea vs. LACT < 1.5%

20 Sensitivity to Fluid Properties At topside conditions (63% GVF, low WLR), PVT properties have almost no impact on total HC mass flow rate at 11 bar pressure Assessment using MPM Recalculation tool (available to operators), using real raw data from a topside meter 20

21 Subsea vs. Topside Low pressure liquid measurements susceptible to the largest model uncertainty metering models configuration adjusted to match total HC mass flow from subsea meters Topside configuration update. Close agreement SS vs. TS vs. LACT

22 Comments/Advice from Chevron Remote Support Work with IT prior to start-up to provide access to the meter terminals remotely. This allows real time support and avoids the need to send technicians offshore Measurement Performance Tracking Build tools to track performance of measurement layers against one another prior to start-up. Integrate the data into a process model to account for shrink and flash between each layer of measurement. Develop a Meter Verification Plan For green-field start-ups, develop a plan on how you will verify measurement capability at each layer.

23 Conclusions A careful verification plan should be established well in advance of start of operations Oil in-situ measurements made by the MPM meter at subsea conditions (HP) can be useful in correcting PVT mode l predictions In-situ measurements are much easier and cheaper than subsea samples (and may produce more accurate results) Verification using hydrocarbon mass flow simplifies the comparison by avoiding uncertainties due to uncertainty in PVT properties and phase transfer

24 Thanks To Ian Bowling (Chevron) For allowing MPM to present this interesting case