real-time subsea pipeline leak monitoring using fiber … acquired data to determine leakage source:...
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Real-time Subsea Pipeline Leak Monitoring using Fiber Optic Sensing Technology
Prem Thodi, Ph.D., P.Eng., Senior Engineering Specialist INTECSEA Canada, WorleyParsons
12th March 2015, Perth, Australia
Introduction
Real-time leak detection needs
Existing leak detection technologies
Internal / primary / CPM systems
External / secondary systems
Periodic leak testing systems
Fiber optic cable DTS and DAS
Distributed leak sensing principle
Key technology gaps
Arctic pipeline leak detection JIP
Summary and conclusions
Outline
Source: www.offshoreenergytoday.com
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Source: www.telegraph.co.uk
Demand for oil and gas will continue to drive deepwater and harsh environment subsea development
Deepwater and harsh environment presents technical challenges
Reliable operational strategies are needed to reduce risk
Real-time pipeline leak detection is an important aspect of safe & economic hydrocarbon development
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Introduction
Subsea Pipeline Leakage –Causes & Consequences
Causes
• Structural degradation – Corrosion, pitting, erosion, and SCC, HIC, fatigue cracking
• High bending strain due to differential settlement and ground movement
• Others – Span, VIV, buckling, collapse• Pipeline connections, valves, fittings• Third party interventions
Consequences
• Safety• Environmental• Economical• Negative reputation
Structural Degradation - Corrosion
Structural Degradation – Cracking
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Real-time Pipeline Leak Detection Challenges
Uncertain minimum thresholds of detection
Remote performance monitoring and control
Subsea equipment and power requirements
Likelihood of false alarms
Background noise reduction
Installation and maintenance challenges
Operational management using SCADA
Uncertain operational reliability
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Source: NAXYS Monitor in Ormen Lange
Existing and Emerging Pipeline Leak Detection Technologies
Leak Detection Technology Types
Internal Based Systems External Based Systems
Periodic Leak Testing Systems
Pressure/Flow Monitoring
Acoustic Pressure Waves
Balancing Methods
Statistical Methods
Real Time Transient Monitoring
Extended RTTM
Bubble Emission Methods
Capacitance Methods
Vapor Sensing Tubes
Optical Camera Methods
Bio Sensor Methods
Acoustic Methods
Fiber Optic Cable Methods
Intelligent Pigging
ROV/ AUV Inspection
Acoustic Pigging
Fluorescent Methods
Electrical Resistance
Remote Sensing Methods
Underwater Gliders
Subsea Towed Systems
PSL Switches
Annulus Monitoring in PIP
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Internal Leak Detection Systems
Utilize field sensor data to monitor pressure, temperature, density, flow rate, contamination, sonic velocity, product data at interfaces
Mass balance system
Pressure monitoring system
Acoustic pressure wave monitoring
Real-time transient monitoring (RTTM)
Extended RTTM
Infer commodity release by computation
Install-able along with pipeline and SCADA
Use acquired data to determine leakage
Source: Wave Alert System (Acoustic Systems Inc.)
Source: Atmos Pipe (ATMOS Intl.)
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Mass Balance & Pressure Monitor
Mass Balance System Pressure Monitoring System
Suitable for Single Phase Oil transport pipelines
Single Phase Oil / Multiphase flow pipelines
Type of Instn. Permanent Permanent
Type of Monitor Continuous Continuous
Advantages • Can detect large pipeline leaks• Well established and matured
technology• Able to detect leaks in transient
flow conditions less accurately
• Can detect large pipeline leaks• Well established and matured
technology• Can be easily integrated into
pipeline SCADA
Disadvantages • Cannot detect small chronic leaks (i.e. sub 1% leaks)
• Prone to false alarms, reported poor performance in transient
• Not intended for use under low-flow or no-flow conditions
• Accurate multiphase leak detection is challenging
• Cannot detect small chronic leaks (i.e. sub 1% leaks)
• Prone to false alarms, reported poor performance in transient
• Potentially requires intermediate monitoring points
• Multiphase flowline leak detection is challenging
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Acoustic Monitoring & RTTM
Acoustic Pressure Wave Monitoring
Real Time Transient Monitoring (RTTM)
Suitable for Single Phase / Multiphase flow pipelines
Single Phase Oil / Multiphase flow pipelines
Type of Instn. Permanent Permanent
Type of Monitor Continuous Continuous
Advantages • Quick leak detection• Good for large leak detection• Can detect location of leak• Simplified sensor and software
set-up with minimal calibration
• Very accurate in steady state • Can detect small leaks (1%)• Good for long oil pipelines• RTTM Software algorithm are
designed for leak location
Disadvantages • Background noise affects leak detection capability for small leak
• Difficult for multiphase flow• Prone to false alarms• No detection capability once the
leak-noise misses the sensor• Challenging for small leak on
long pipeline (>40km)
• Extensive instrumentation is needed (flow, temp, pressure)
• Unsteady flow creates errors (or, false alarms)
• Calibration error could cause missed leaks or false alarms
• Sensitivity reduces with ultra long pipelines
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Internal leak detection systems can detect large leaks
Easy installation and maintenance
Limited ability to detect small, chronic leaks (sub 1% leak)
Limited capability to locate leaks accurately
Leak detection capability reduces with operations, like:
Startup and shutdown
Valve closures
Transient flow
Multiphase flow
Prone to false alarms
Cannot use under low-flow or non-flow conditions
Pros and Cons – Internal LDS
Source: Pressure Point Analysis (EFA Tech.)
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External Leak Detection Systems
Measures physical properties (temperature, acoustics, presence of oil particle, capacitance) around the pipelines
Can be fixed on to pipelines or kept adjacent to pipelines
Can be easily integrated into pipelines SCADA
Hydrocarbon Vapor Sensors
Fiber Optic Cable Sensors
Vacuum Annulus Monitors (for PiP)
Acoustic Sensors
Capacitance Sensors
Remote Sensors
Fluorescence & Optical TechnologiesSource: Methane Vapor Sensor (Areva NP GmbH)
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Vapor Sensing Tubes & Fiber Optic Sensing
Vapour Sensing Tubes Fiber Optic Leak Sensing
Suitable for Single Phase Oil / Multiphase flow pipelines and equipment
Single Phase Oil / Multiphase flow pipelines
Type of Instn Permanent Permanent
Type of Monitor Continuous monitoring Continuous monitoring
Advantages • 30 years of service history, less unknowns
• Capable of detecting small chronic leaks (0.1m3/hr gas)
• Leak location accuracy is approx. 0.5% of total length
• Can work under low flow conditions
• Can detect very small leaks accurately (sub 1% leaks)
• Can locate leaks very accurately• No data link needed, no subsea
power requirement, no electrical / EM interference, shutdown not required for calibration
• Can be used on long pipelines
Disadvantages • Length and depth limitations are 15km and 15m
• Slow detection (i.e. 24hrs), additional protection required
• Handling, installation and maintenance are difficult
• Only detects leaks that evolve into sensing tube
• Multiple interrogator units are required for long (>50km) pipelines
• Increased installation cost for sensor and interrogator system
• Needs enhancement in technology readiness level
Can detect small chronic (sub 1%) leaks
Can locate small leaks accurately
Can be used for long pipeline continuous leak monitoring
Dependent on ocean diffusing material to the sensor
Likelihood of false alarms
Requirement of differential pressures
Installation and maintenance difficulties
Requirement of permanent installations
Difficulty in quantifying size and rate of leak
Pros and Cons – External LDS
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Periodic Leak Detection Systems
Not a continuous (i.e. 24x7) leak monitoring system
Can be used for periodic leak testing, or when a leak is suspected
Intelligent pigging
Acoustic pigging
ROV/AUV/overflight inspection
Acoustic (active) technology
Optical (camera) technology
Underwater gliders
Underwater towed systems
Need support vessel for periodic ROV/AUV operation Source: NAXYS SALD (Left) and ALVD (Right)
Source: COLMAR ALD mounted on ROV
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Distributed Temperature Sensing (DTS) Systems
Oil leakage leads to local rise in temperature
Gas leakage leads to local cooling
FOC itself acts as the sensor and data link
Raman band systems Brillouin band systems
Distributed Acoustic Sensing (DAS) Systems
Acts as a hydrophone Captures acoustic signature
(i.e. vibration) generated by leaking fluid
Noise separations No need to contact fluid with
FOC sensors Rayleigh band systems
Fiber Optic Cable Distributed Sensing Systems
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Principles of Operation
Distributed Temperature Sensing
Raman DTS System Based on intensity of
backscattered signal Measures local change in
temperatureBrillouin DTS System Converts temperature effects
on cable into frequency shifts of backscattered light
Insensitive to the fiber attenuation changes over time and distance
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Distributed Acoustic Sensing
Rayleigh DAS
Measures minute strain effects on the sensor
Strain is caused by acoustic vibrations
Leak acoustic waves modulates the backscattered signal
Cable pick up the acoustic signals, and when a distinguishable signature is detected, an alarm is triggered
When a short pulse of light is emitted, a proportion of the outgoing signal is scattered back to source due to impurities or defects in fiber microstructure
OTDR Principle for Distributed Sensing Systems
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Optical Wave Spectrum (Raman, Brillouin, Rayleigh) Principle of Optical Time Domain Reflectometer
Light pulse
Ba
cksc
att
ere
d s
ign
al
Localization
Sensing fiber
Optical Source
Detector
Stokes ComponentsAnti-Stokes Components
ν
Ω
ν - Ω
ν + Ω
Ω
ν
Stokes Component
Anti-Stokes Component
FOC Distributed Sensing Leak Detection System Components
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1. HDPE outer sheath2. Galfan high strength steel wire3. Gel-filled metal tube SS 316L4. Bend insensitive optical fibers
Typical DTS Cable
1. PA Outer sheath2. Stainless steel 316 L metal tube3. Inner interlocking system 4. Multilayer acoustic coupling layer5. Bend insensitive optical fiber
Typical DAS Cable
Typical Optical Budget Requirements
Optical Loss Calculations for Distributed Temperature Sensing (DTS) SystemsDeepwater Pipeline LossesOptical Loss per Splice 0.10 dB/splice No of splices 3 Splice Loss 0.3Optical Loss per Connector
0.50 dB/connectorNo of
connecters2
Connector Loss
1.0
Fiber Loss per km 0.36 dB/kmPropagationlength (km)
80 Fiber Loss 28.8
Safety Margin 3.00 dB
Total Loss (dB) 33.1
Optical Loss Calculations for Distributed Acoustic Sensing (DAS) SystemsDeepwater Pipeline LossesOptical Loss per Splice 0.1 dB/splice No of splices 3 Splice Loss 0.3Optical Loss per Connector
0.3 dB/connectorNo of
connecters4
Connector Loss
1.2
Fiber Loss per km 0.2 dB/kmPropagationlength (km)
80 Fiber Loss 16.0
Safety Margin 3.0 dB
Total Loss (dB) 20.5
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Technology Status (TRL/TRC)
Technology Readiness Levels (TRL)
Technology Risk Categorization (TRC)
Major ComponentsTechnology
Readiness Level Key Points (API RP 17N)DAS DTS
Interrogator Unit
3 3
Concept proven, prototype tested in lab for performance, functionality, reliability. Pre-
production system environmental (i.e. deepwater) test not yet performed.
Processing UnitControl UnitSensing FOC
DTS & DAS
Reliability TechnologyArchitecture/
Config.Operating
EnvironmentOrg. Scale/ Complexity
Overall Risk
Risk Category
High (B) High (B) High (B) Very High (A) High (B)Very High
(A)
Key Points
False AlarmsMTBF Install-ability
Long Length Install-ability
New Application
Deepwater LDS
Uncertainty
Relatively New Team
Technology Readiness Levels (TRL)
Technology Risk Categorization (TRC)
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FOC Positioning for Deepwater Pipeline Leak Detection
Assumptions:• Positioning is based on damage prevention during installation as well as
increased detectability regardless of leak location and current direction• FOC sensor needs to be close to the leakage for effective leak detection
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Need to pass over lay vessel and stinger roller supports
Lay barge reconfiguration requirements
Limitations of cable splices offshore
Optimum location or orientation of DTS and DAS cables
DTS cable need to be in close proximity to the pipeline, DAS can be away
Cable repair is challenging, so need to consider providing redundancy
Installation and maintenance of subsea (marinized) repeaters
Fiber Optic Cable Installation & Maintenance Challenges
S-Lay
Reel Lay
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Minimum thresholds of detection
Inadequate technology status
False alarm reduction
Reliability of systems
Long pipeline application
Sensor positioning/orientation
Lack of deepwater experience
Interrogator installation and repair
Leak size quantification difficulty
Technology Gaps
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Overall aim of the JIP is to test detectability, determine minimum thresholds of detection (i.e. minimum leak rate & response time), enhance technology readiness level, simulate cold-region, deepwater environmental testing, and identify false alarm rate
Phase I – Designing, costing, scheduling and execution planning to establish the basis and boundary of the testing program
Phase II – Large scale field testing in a simulated environment in St. John’s, Newfoundland and Labrador, Canada
R&D Initiatives on FOC Testing
General Test Setup
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Completed JIP Phase I Tasks
Definition of physical test
Test facility selection
FOC DTS / DAS selection
Optimal sensor positioning
Testbed geotechnical evaluation
Test procedure development
Cost and schedule development
Test HSE management plan
Phase II – Large scale field testing
(proposed)
R&D Initiatives on FOC Testing
Novelties
Long cable (up to 40 km)
Low ambient temperature (4°C)
Large test tank (20 x 10 x 3m)
Integrated (DTS/DAS) testing
Small leak detection testing
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Pipelines are designed to safely transport produced hydrocarbons
Pipeline leaks can have severe safety, economical and environmental consequences
Existing leak detection technologies
Internal / Primary / CPM systems
External / Secondary systems
Periodic Leak Testing systems
FOC DTS and DAS technologies
Operating principles
Optical budget requirements
Installation and maintenance
Technology status (TRL/TRC)
Key technology gaps are identified
R&D initiatives to close the specific gaps
Summary & Conclusions
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DISCLAIMER
This presentation has been prepared by a representative of WorleyParsons.
The presentation contains the professional and personal opinions of the presenter, which are given in good faith. As such, opinions presented herein may not always necessarily reflect the position of WorleyParsons as a whole, its officers or executive.
Any forward-looking statements included in this presentation will involve subjective judgment and analysis and are subject to uncertainties, risks and contingencies—many of which are outside the control of, and may be unknown to, WorleyParsons.
WorleyParsons and all associated entities and representatives make no representation or warranty as to the accuracy, reliability or completeness of information in this document and do not take responsibility for updating any information or correcting any error or omission that may become apparent after this document has been issued.
To the extent permitted by law, WorleyParsons and its officers, employees, related bodies and agents disclaim all liability—direct, indirect or consequential (and whether or not arising out of the negligence, default or lack of care of WorleyParsons and/or any of its agents)—for any loss or damage suffered by a recipient or other persons arising out of, or in connection with, any use or reliance on this presentation or information.