Leak detection methods

 LEAK DETECTION METHODS FOR ONSHORE PIPELINE

Leak detection is used to determine where a leak has occurred in liquid and gas pipeline systems. Methods of detection include hydrostatic testing (hydrotest), infrared, and laser technology after pipeline erection and leak detection during service.

The likely causes of pipeline leakage

 Causes of pipeline leakage can be divided into five main categories:

o   Internal and external corrosion

o   Third party damage

o   Operational error

o   Natural hazards

o   Mechanical failure

Leak detection for the pipeline may be achieved by the provision of equipment (eg. Pipeline Integrity Monitoring & Leak Detection Systems (PIMS)) to undertake constant monitoring of pressure sensing devices located at each end of the pipeline and at the intermediate isolating valve stations.

The output from these monitoring devices, should be displayed in the main control room, and thereby enable the operators to identify abnormal or unexplained deviations in pressure and to shut in the pipeline section affected by actuating the intermediate/block isolating valves.

In addition to the above, any PIMS/SCADA system, metering should be installed at each end of the pipeline. The signal from the meter at the receipt terminal should be transmitted to the main control room (usually the pumping end of the pipeline) for comparison with the outgoing meter signal. Any unexplained deviation from a predetermined threshold value should alert the operators as to a possible leak or malfunction.

Leak detection system may be classified as

a.    Internal-based leak detection system.

b.    External –based leak detection system

External – based leak detection system can detect the smallest leak with high accuracy.  Internal-based leak detection discovers gas leakage based on measurement reading at some specific location along the pipeline. eg. Computational Pipeline Monitoring (CPM)

 

The main aim of leak detection is to help pipeline operators to detect and localize leaks. The following methods may be used to detect leaks in pipelines.

1.    Water immersion bubble test method

2.    Soap solution bubble test

The pressurized unit to be tested is sprayed with a soap solution and the operator is able to see the bubbles formed by gas escaping from where the leak is.

3.    Software based leak detection system

Computational Pipeline Monitoring (CPM) systems (also called software based leak detection systems) use pipeline data to infer leaks on the pipeline and/or to alarm upon hydraulic anomalies that have the characteristics of a leak. These systems are in place to alert the Pipeline Controller so he/she can evaluate the cause and as necessary to shut-down the pipeline and minimize the size of a spill.

4.    PIMS/SCADA – based system

A leak detection system can be integrated into the SCADA system in the control room. SCADA systems can alert personnel in the control room whenever there is a leak as well as record keeping and trending before and after the event. Locating the leak with a precise location facilitates quicker response and repairs.

5.    Fiber optic sensing technology

Leaks can cause sudden temperature changes in the soil surrounding a pipeline. Fiber optic cables buried along pipelines can sense these temperature changes, as well as acoustic vibrations from a leaky pipe. Signals are then sent to the control room and anything out of the ordinary triggers alarms.

6.    Detecting leaks through pressure changes

A leakage can cause a noticeable change in gas pressure. Therefore sensors can be installed to detect changes in the pressure of the pipeline. Changes in pressure can trigger an alarm. The sensors required for this technique can be categorized as flow, pressure, and temperature.

7.    External Leak Detection Equipment

External leak detection equipment can be installed on the pipeline. Detection equipment can monitor the dynamics of the flow for changes that would indicate a leak.

8.    Intelligent pigging

Small leaks can produce ultrasonic signals which can be detected by a pig propelled forward by oil flow over several seconds, allowing several hundred samples. Very small leaks can be detected by this method. The disadvantage of this method is frequent requirement of pigging.

9.    Radioactive tracing

10. Acoustic emission systems

The presence of a leak is manifested by an increased noise level. The sound generated by leak can be used as a means of leak detection and location.

11. Chemical based systems

12. Observing the environment for suspected natural gas pipeline LEAK:

Any one of these is a sign of a suspected natural gas pipeline LEAK:

a.    Whistling or hissing sound;

b.    Distinctive, strong odor, often compared to rotten eggs;

c.    Dense fog, mist or white cloud;

d.    Bubbling in water, ponds or creeks;

e.    Dust or dirt blowing up from the ground; or

f.     Discolored or dead vegetation above the pipeline right of way.

Table 1: Technical Specification for Onshore Leak Detection System

Minimum Technical Specification of leak detection equipment

1.    SYSTEM COMPONENTS

A.   Sonic Sensors ·         Mechanically mounted inside all-weather casing and bolted into the pipeline. ·         Sensor must have 10-30 volt supply powered by remote units ·         Output capacity 4-20mA current signal ·         Two (2) wire instrumentation cable required for connection between sensor and remote units ·         Indicate distance between sensors ·         Sensors operate in the range of 10MHz to 400kHz ·         Sensors shall be strategically installed at various locations along the pipeline. ·         The distance between sensors should be varied and factors including the following must be considered. o   Characteristics of the pipeline o   Fluid o   System performance requirements o   Calculated acoustic signal attenuation in the fluid and or gas ·         The use of a pair of sensors at the two ends of the pipeline segment must allow for the identification and rejection of the external operational noises generated outside the monitored segment that otherwise would cause false alarms. ·         Sensors to be installed on the pipeline must be rated to the maximum pressure of the pipeline and must adopt an installation that avoids or eliminate costly shutdown.

B.   REMOTE TERMINAL UNITS ·         The field devices may be dedicated for the application or shared with a DCS (Distributed Control System) or SCADA system. Selection of either approach will be determined by the application performance measures. This also may determine the use of dedicated communication media and operator interface subsystems. ·         Remote terminal units must be provided and installed in the field and in close proximity to the sensors.  ·         The Remote terminal units shall be placed in a standard rack mount cabinet located in the equipment shelter. Each unit must support one pair of sensors, and must function to conduct a pre-filtering of the data acquired by the sensors and send them over digital communication to the central monitoring station. ·         The Remote terminal units should be connected to the Central Monitoring Station via a single or a combination of media, such as optical fiber, GPRS, radio, satellite, etc.

C.   CENTRAL MONITORING STATION ·         The System configuration and operation must be performed on a dedicated computer running non-proprietary supervisory software. ·         The System must act as a Human-Machine Interface (HMI), and features customized pictographic screens illustrating pipeline aerial views and highlighting the monitored points and many other vital system parts. ·         The System configuration parameters and operating conditions must have the capacity to be inputted into the supervisory software through user friendly engineering screens. ·           The System must have the capacity to detect and confirm a leak; an alarm system should be activated to sound off to show the exact location of a leak with date and time captured. ·         Ability to customize an HMI screen in various ways to the Client (if required). Amongst the main functions and characteristics of the central monitoring station (CMS) leak detection module are: o   Carry out complex multi-layer signal filtering and data processing. o   Utilize filters (band pass filters, differential filters, phase filters, floating average filters, correlative filters, mask filters, neural filters, and adaptive gain blocks). o   Compare acquired signals with embedded masks. o   Analyze and evaluate data received from sensors to validate and confirm an event (leak). o   Clock synchronized by satellite among all remote terminal units in use. o   Utilizes re-programmable leak masks. o   Perform internal diagnostic tests and report faults. The supervisory computer system is responsible for various informational, communication, security and diagnostic functions. In addition, it manages and maintains an intricate database and reports as well as historical event logs.

2.    PIPELINE PROTECTION COVERAGE The offered system must offer 100% pipeline coverage without any muting or dead zones.

3.    SYSTEM PERFORMANCE a.    The leak detector must be fast, simple and straight forward in obtaining data without having to depend on third party instruments or proprietary software. b.    Ability to deal with transients conditions without causing spurious alarms. c.    Should comply with the following standards ·         API  RP 1130 - Computational Pipeline Monitoring ·         API 1149 - Pipeline Variable Uncertainties & their Effect on Leak Detectability ·         ISO 5168 - as part of the sensitivity study requirements ·         Environmental Protection Agency o   EPA530/UST-90/010 - Standard Test Procedure to Evaluating Pipeline Leak Detection Method: Pipeline Leak Detection System

4.    PERFORMANCE CRITERIA

A.   Reliability Pipeline leak detection system must correctly report any real alarms, and also does not generate false alarms. Table 2: Minimum levels of reliability for Pipeline Leak Detection System selection Level Description High Shall not exceed one false alarm per year for the high sensitivity level stated in Table 3. Medium Shall not exceed three false alarms per year for the medium sensitivity level stated in Table 3. Low Shall not exceed five false alarms per year for the low sensitivity level stated in Table 3. B.   Accuracy Accuracy of calculated leak rate = ± 10% of reading C.   Response time ·         Ability to declare an alarm in seconds or minutes rather than hours or days ·         Detects a specific and unique sonic wave which travels from the source of the leaks onset to strategically laced sensors at the speed of sound. D.   Robustness ·         The leak detection system should withstand extreme environmental conditions. ·         Has the ability to continue to function and provide useful information, even under changing conditions of pipeline operation, or in conditions where data is temporary lost or suspected to be lost. Table 3: Minimum levels of robustness for Pipeline Leak Detection System selection Level Description High Loss of a field sensor/communication link will not degrade performance Medium Loss of a field sensor/communication link may reduce accuracy and/or sensitivity of detecting leaks by one level of Table 1 and or 2 Low Loss of a field sensor/communication link may cause failure to detect leaks. E.   Sensitivity ·         The system must have the capacity to detect leaks of any size within seconds to few minutes (max) from the time of occurrence of leak. ·         The system sensitivity must be a variable value, and differs according to pipeline arrangement. Table 4: Sensitivity requirement for gas pipeline Level Description Operating pressure range High 18mm(0.75inch) of leak size within 3 minutes Greater than 42barg 18mm(0.75inch) of leak size within 5 minutes 21barg – 42barg 18mm(0.75inch) of leak size within 7 minutes Below 21barg Medium 18mm(0.75inch) of leak size within 10 minutes Greater than 42barg 18mm(0.75inch) of leak size within 12 minutes 21barg – 42barg 18mm(0.75inch) of leak size within 15 minutes Below 21barg Low 18mm(0.75inch) of leak size within 1 hour Greater than 42barg 18mm(0.75inch) of leak size within 1  and half hour 21barg – 42barg 18mm(0.75inch) of leak size within 2 hours Below 21barg

5.    LEAK MONITORING PACKAGE – SOFTWARE ENGINE ·         Leak monitoring software shall provide continuous operator alert and logging functions for the pipelines including real time simulation capability for diagnostics ·         Leak monitoring software shall provide history archive of actual leak detected and suspected or filtered events. ·         Leak monitoring software shall provide report to indicate leak details with capability to print or display on the designated operator workstation. The system shall report the location of the leak within time fame that does not exceed twice of the Pipeline Leak Detection time specified in Table 1. The report may include topographical locations coordinates, etc.

6.    TESTING (1)  Factory acceptance test (FAT) shall be conducted by a four (4) member team of the purchaser after contract award, and prior to shipping of the equipment. (2)  The tenderer shall include the travel cost of the said team in the total tender price. (3)  Pre FAT testing should be conducted and proof submitted thereof by the Supplier before witnessed FAT is arranged. (4)  Field test of leak detector shall be provided upon commissioning. (5)  The Leak Detection System shall be tested to comply with the followings: a.    Performance measures determined by the leak detection (risk assessment) study per Purchaser Factory Acceptance Test standards Or, b.    Approved international standard procedures (i.e., API, EPA), Proponent test procedures and requirements.

7.    FIELD INSTRUMENTATION The application and installation of Pipeline Leak Detection field instrumentation shall meet the reliability and robustness measures stated above. Conventional instruments such as pressure, temperature, etc., shall meet requirements of standards stated in Section 3.c of system performance above. Other instruments shall be selected based on selected Pipeline Leak Detection System recommendation.

Subsea leak detection system

The offshore leak detection system should satisfy the requirement of ISO 13628-6.

There are water/oil/liquid leak detection systems available which can be used to detect oil leakage if the pipeline is transporting liquids

Table 2: Technical Specification for Subsea Leak Detection System

Leak Detection Technology

Calibration/Recalibration

Maintenance

Mechanical Interface

Weight (Kg)

Dimensions

Connection To Power And Communication

Power Need

Bandwidth Need

Detectable Release Limit Or Other Accuracy Information

Detectable Media

Detection Range

Reliability Data

Design Life (Years)

Water Depth (m)

Temperature (°C)

Capacitance

No recalibration

Cleaning using a hydro-jet should be ok

Bolted on to cover above leak point

<5

<1000ccm=1.1

4-20mA and CANBus

24V, 0.5W

Low

Even small leaks are detected

All hydrocarbons

Depending on overall system design

Approx. 300 units delivered, no returns and no reports of failure after installation

25

4000, deeper if required

All sea temperatures OK

Fiber optic

No calibration

2 years

System specific

20kg-surface equipment

56x45x15cms

Ethernet at surface

240/110v 300w at surface

System specific

Gas bubble at 1Hz detected. Low pressure threshold approx. 2bar. No upper limit

Not depended on chemical compound, detects vibrations caused by a leak

Dependent on energy, but typically 5m

-

20

4000

+5 to +50 (operation)

Fluorescent

No recalibration required

Possible lens cleaning every 3-5 years

Bolted on to XT and SPS

10-15 in air

Ø200x200m, 100x200x200mm

4 wire Tronic/ CANbus/ 4-20mA

24V, <10W

Low

Wide dynamic range < 100ppm @ 4m

Crude oil production fluids with fluorescent markers

3-5m

-

N/A

N/A

N/A

Optical camera

No

Check moving parts and lens cleaning every 2 years. Intervention every 5 years

ROV mountable on Xmas tree, no pre installation required

Camera 3.2 in air. Light 4.1 in air

Ø100 x 200mm. 880*550*450

4 wire tronic. Communication via power line

96W

Medium communication on separate line or via subsea control system

-

All hydrocarbons and injected chemicals

10 meters

N/A

25

1000 made in aluminum 3000 made in titanium

Passive acoustic

Adapts to background noise at installation site. No recalibration required

None

ROV mounting, for larger type of systems a special cone is required

Smaller type 2-3, larger type 250 in air

Smaller type Ø 64x 357mm, larger type Ø1 x 1.8m

N/A

Larger type: 25W

Dependent on processing subsea or topside processing topside requires more band width

Smaller type: 5 liter/min @ 25 Bar diff pressure at 2m distance. Detection range 50m with increased leakage rate. Larger type: 5liter/min @ 5Bar diff pressure at 5m distance. Detection range 1000m with increased leakage rate.

Not important

-

-

5 for small type and 25 for large type

2500

Operational in sea water: 5 - +30. Onshore test temperature: – 20 - +70. Storage: – 40 - +70

Active acoustic

Calibration during sea acceptance test

3-5 years interval

Mounted on ROV skid or directly to template structure. Will be designed to be ROV retrievable.

Receive array 9.6 (dry), subsea bottle 24.8 (dry), transmit array 4.5 (dry),

Receiver: 102 x 496 x 131mm. Transmitter: 240 x 86 x 99mm. subsea bottle: 530.9 x 174mm

48V, Ethernet

40W – 100W

High development goal is 1 – 10Mbit Ethernet interface

Small gas leakages (0.35mm nozzle, 2bar pressure difference) detected at about 30 meters. Fluid leak from 5mm nozzle with 15bar pressure difference detected at 50m.

Not dependent on chemical compound as long as acoustic impedance is different to that of sea water

Depends on leak size and media. Small gas leaks seen up to 125m range. Fluid seen up to 50m range (maximum test range to date)

N/A

N/A

400 and 6000 versions

-5 to 40 (operation),     -30 to 55 (storage)

Calibrates automatically at installation. No recalibration needed

Deepening on water depth from 4-8years interval.

ROV mountable on Xmas tree, no pre installation required

<11kg complete unit (dry)

226 x 62 x 154mm

15-36V 100Mb/s Ethernet 16Mb/s RS-485

Type: 15W <30W – dependent on required updating rate

Dependent on requirement and information, can be low 9600 Baud system specific

Angular resolution < 0.75° Range resolution < 10mm

Not dependent on chemical compound as long as acoustic impedance is different to that of sea water

Angle horizontal 90° or 120°. Angle vertical 20°. Range 1 to < 100m

N/A

25

300 or 3000

-20 - 60

Bio sensors

Calibration after installation

Replacement of biosensor module

Installed in a sensor rack integrated or in proximity of the monitored structure

Bio sensor module 2-3 (in air)

Prototype racks are 2m x 0.4m x 0.4m (physical, chemical and biological sensor array)

Connected to subsea control system via cable RS -485 or Ethernet

Approx. 10W

Low

< 0.06ppm on hydrocarbons (raw oil)

Not dependent on chemical compound, specification  will depend on selected biosensor

Depending on leak size, media and sea current (upstream/ downstream approach)

N/A

N/A

100(500 from 2012)

Ocean temperature range

Methane sniffer: semi-conductor

2 years

2 years

Adaptable to fit application

0.5kg in water

Ø49mm x 200mm

Wet mateable plug

1W

Low

Very small leaks

Methane

Lower range limit 1 nM (oceanic back-ground)

Lifetime 5 years

5

4000

0-30

Note: Subsea = shallow water or deep water,                   N/A = Not Applicable,                     XT = Xmas tree,                   SPS = subsea processing system,            ROV = Remote Operated Vehicle,          CAN bus =  controller area network,