pipepatrol - principles of leak detection en krohne

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Principles of Leak Detection

Prof. Dr.-Ing. Gerhard Geiger



Introduction

Fundamentals of Leak Detection KROHNE Oil & Gas 2



Introduction

Contents

1 Introduction 7 2 Regulatory Framework 8 2.1 TRFL (Germany) 8 2.1.1 Installations according to TRFL a) and b) 8 2.1.2 Installations according to TRFL c) 8 2.1.3 Installations according to TRFL d) 8 2.1.4 Installations according to TRFL e) 9 2.2 API 1130 (USA) 9 2.3 API 1155 (USA) 9 3 Pressure/Flow Monitor ing 10 3.1 Pressure Monitoring 10 3.2 Flow Monitoring 10 3.3 Summary 10 4 Negative Pressure Wave 12 4.1 Summary 12 5 Balancing Methods 14 5.1 Mass Balance 14 5.1.1 Uncompensated mass balance 14 5.1.2 Compensated mass balance 15 5.2 Use of volumetric flow meters 15 5.3 Summary 17 6 Statistical Leak Detection Systems 19 6.1 Probabil ity Ratio Test 19 6.2 Sequential Probabili ty Ratio Test (SPRT) 20 6.3 Summary 20 7 Leak Location 22 7.1 Gradient Intersection Method 22 7.2 Wave Propagation Method 22 8 RTTM – Real Time Transient Model 23 8.1 Compensation Approach 25 8.2 Head Stations Residual or Differential Approach 26 8.3 Substations Residual or Differential Approach 27 8.4 Flow Calculation 27 9 PipePatrol Statistical Mass Balance (SMB) 28 9.1 Summary 28 10 PipePatro l Extended Real-Time Transient Model (E-RTTM) 31 10.1 Leak Signature Analysis 31 Fundamentals of Leak Detection KROHNE Oil & Gas 3



Introduction


10.2 Leak Location 31 10.3 PipePatrol E-RTTM/PC – Leak Detection in Pumping Condit ion 32 10.3.1 Head stations monitoring 32 10.3.2 Substation monitoring without flow measurement 33 10.3.3 Segment monitoring for substations with flow measurement 34 10.3.4 Leak detection with substations and virtual flow monitoring 35 10.4 PipePatrol E-RTTM/SC – Leak Detection in Shut-in Condit ions 37 10.4.1 Head Station Monitoring 37 11 Comparison of all methods 41

Index of figures

Figure 1: Calculation of mass flow from volumetric flow .............................................................. ........................... 16 Figure 2: Conditional probability density functions ......................................................................... ........................ 19 Figure 3: Leak location by gradient intersection method ...................................................................... .................. 22 Figure 4: RTTM to calculate local profiles; model using pressure readings ......................... .................................. 24 Figure 5: RTTM to calculate local profiles; model using flow readings ..................................................... .............. 24 Figure 6: Compensated mass balance with RTTM based compensation .................................... .......................... 25 Figure 7: Residual or differential approach for head station monitoring ................................................................. 26 Figure 8: Residual or differential approach for pressure substation ................................................................... ... 27 Figure 9: Functionality of PipePatrol SMB ............................................................ .................................................. 28 Figure 10: PipePatrol E-RTTM/PC: pumping conditions, head station monitoring ................................................. 32 Figure 11: PipePatrol E-RTTM/PC: pumping conditions, pressure at substations .............................. ................... 33 Figure 12: PipePatrol E-RTTM/PC: pumping conditions, PTF substations............................................. ................ 34 Figure 13: PipePatrol E-RTTM/PC: pumping conditions, PT substations ............................................................... 35 Figure 14: PipePatrol E-RTTM/PC: pumping conditions, P substations .......................................................... ....... 36 Figure 15: PipePatrol E-RTTM/SC: shut-in conditions, no substations .................................................................. 37 Figure 16: PipePatrol E-RTTM/SC: shut-in condition, P substations ........................................................... ........... 38

Index of tables

Table 1: Symbols, labelling, units - part 1...................................................... ........................................................ 1-6 Table 2: Symbols, labelling, units - part 2...................................................... ........................................................ 1-6 Table 3: Functionality and instrumentation of Pressure and Flow Monitoring . .......................................... ............ 10 Table 4: Fields of application of Pressure- and Flow Monitoring. ........................................................................... 10 Table 5: Performance Parameters of Pressure and Flow Monitoring. ....................................................... ............. 11 Table 6: Functionality and instrumentation for negative pressure wave. ................................................................ 12 Table 7: Fields of application for negative pressure wave. ......................................................... ............................ 12 Table 8: Performance Parameters of Negative Pressure Wave ..................................................... ........................ 13 Table 9: Functionality and instrumentation for balancing methods.................................................... ..................... 17 Table 10: Fields of application for balancing methods. ................................................................. ......................... 17 Table 11: Performance parameters for balancing methods..................................................... ............................... 18

Table 12: Functional summary of statistical LDSs. ....................................................... .......................................... 20 Table 13: Fields of application for statistical LDSs. .................................................. .............................................. 20 Table 14: Performance parameters for statistical LDSs. ........................................................................................ 21 Table 15: Functionality and instrumentation of PipePatrol SMB. ....................................................... ..................... 28 Table 16: Possible fields of application of PipePatrol SMB. ................................................................................... 29 Table 17: Performance parameters of PipePatrol SMB. ........................................................... ............................. 30 Table 18: Functionality and instrumentation of PipePatrol E-RTTM. ........................................................... ........... 39 Table 19: Possible fields of application of PipePatrol E-RTTM. .................................................. ........................... 39 Table 20: Performance parameters of PipePatrol E-RTTM. ................................................................ ................... 40 Table 21: Comparison of all methods for leak detection. .................................................... ................................... 41



Introduction

Symbols, Labelling, Units

Symbol Synonym SI-Unit

A Cross section of the pipeline m2

c Speed of sound m/s

Q Mass flow or volumetric flow kg/s, m3/s

L Length of pipeline m

M Gas specific molar mass kg/mol

M Mass kg

Leak M Actual drained leak-mass kg

Pipe M Mass stored in pipeline kg

M & Mass flow in general kg/s

I M

& Mass flow inlet kg/s

Leak

O

M & Leak flow kg/s

M & Mass flow outlet kg/s

n Number of substations

( , ) N μ σ Gaussian distribution

p Pressure Pa

P Probability in general

0

1P

P Probability for correct decision under leak free conditions

Probability for correct decision under leak conditions

FAP Probability for false alarm

M P Probability for false decision under leak conditions

R Gas constant (8.314472) J/(mol K)

S R Specific gas constant J/(kg K)

s One-dimensional coordinate along the pipeline m

t time s

, F T T Temperature of fluid K

GT Temperature of ground K

v Velocity of fluid m/s

I v Velocity of fluid at inlet m/s

Ov Velocity of fluid at outlet m/s

V Volume in general m3

V & Volume-flow in general m3/s

I V & Volume-flow at inlet m3/s

ref V & Volume-flow at reference conditions sm3/s

OV & Volume-flow at outlet m3/s

VCF Volume correction factor

x Flow residual inlet kg/s

y Flow residual outlet kg/s

z Pressure residual in general Pa




Introduction

Fundamentals of Leak Detection KROHNE Oil & Gas

Table 1: Symbols, labelling, units - part 1.

Symbol Synonym SI-Unit

α Level of significanceε Coefficient of SPRT

γ Smallest detectable leak rate kg/s

λ Coefficient of SPRT

μ Mean of the Gaussian distribution

ρ Density of the fluid kg/m3

σ Standard deviation of the Gaussian distribution

Z Compressibility factor

Table 2: Symbols, labelling, units - part 2.

6



2 Regulatory Framework


2.1 TRFL (Germany)

TRFL stands for „Technische Regel für Rohrfernleitungen“ [TRFL], which was published in 2003 in Germany and appliesto all Pipelines that transport flammable and/or dangerous liquids or gases. Chapter 11.5 of the TRFL requires leakdetection systems all such pipelines. It demands:

• Two autonomous, continuously operating systems that can detect leaks in steady state conditions.

• One of these systems, or a third one, able to detect leaks in transient conditions.

• One system to detect leaks in shut-in conditions.

• One system to detect gradual leaks.

• One system to detect the leak position.

2.1.1 Installations according to TRFL a) and b)[TRFL] requires two autonomous, continuously operating systems that can detect leaks in the steady state. Either of these systems, or both, or a third one, must be able to detect leaks in transient conditions.

Redundant instrumentation is required in principle, but in practice the requirement for redundant equipment is frequentlyrelaxed. This may happen either because the risk of damage to life and property is relatively low, or because instrumentsat substations effectively provide back-ups for each other. Redundant signal paths and communication are alwaysrequired, however. The leak detection system itself must always be redundant, for example using multiple techniquesincluding:

• Pressure and Flow monitoring Chapter 3

• Acoustic/negative pressure wave Chapter 4

• Line balance methods Chapter 5• Statistical LDS Chapter 6

KROHNE Oil & Gas offers with PipePatrol state-of-the-art leak detection systems as:

• PipePatrol Statistical Mass Balance (SMB) Chapter 9, and

• PipePatrol Extended Real-Time Transient Model (E-RTTM) Chapter 10.

2.1.2 Installations according to TRFL c)

[TRFL] requires that each pipeline has one system to detect leaks in shut-in conditions1

. Chapter 11 lists the methodsthat fulfil these needs. PipePatrol E-RTTM Chapter 10 uses a model-based pressure-temperature method, which can be

applied to liquids and gases. In shut-in conditions, valves will lock a pressure into one or more sections of the pipeline. Itis possible for considerable pressure changes to occur in this case as a result of thermal effects, but any rapid or unexpected fall in pressure indicates that a leak has occurred.

2.1.3 Installations according to TRFL d)

Typically these systems utilise a sensor cable installed along the pipeline. Leak detection is either by change intemperature (fibre optics) or change in gas concentration (semi permeable sensor cable). The following should be takeninto account:

• The operating pressure and temperature must be suitable

• Not all fluids can be monitored.

8

1

This point is relevant to liquid pipelines, but flow in gas pipelines is normally continuous. Nevertheless, the TRFL requirement appliesto all pipelines in principle.






If accurate flow, pressure and temperature readings are available, PipePatrol SMB Chapter 9 can be applied. If adequate, leak tight valves are present, the PipePatrol E-RTTM/SC model based pressure-temperature method can alsobe applied, Chapter 10.4.

2.1.4 Installations according to TRFL e)

The TRFL requires the LDS to locate the position of a leak as fast as possible. This function can be integrated into one of the systems installed to comply with section a) – for example, PipePatrol E-RTTM, Chapter 10. Details of leaklocalisation are described in Chapter 7.

2.2 API 1130 (USA)

The second edition of API (American Petroleum Institute) standard 1130 “Computational Pipeline Monitoring (CPM) for Liquid Pipelines” was released in 2002 [API 1130]. API 1130 does not directly impose legal requirements on pipelineoperators in the same way as TRFL, but it provides the necessary technical information for conscientious operators tooperate their pipelines safely.

[API 1130] covers liquid pipelines only. It describes design, implementation, test and operation of Computational PipelineMonitoring (CPM) systems, based on an algorithmic approach to leak detection. It also gives recommendations for (self)test and operator training.

LDSs are divided into two groups:

• External systems use dedicated measurement equipment, such as a sensor cables

• Internal systems use existing measurement sensors providing flow or pressure readings. All LDSs introduced in thissurvey are part of this group.

2.3 API 1155 (USA)

The [API 1155] “Evaluation Methodology for Software Based Leak Detection Systems” was first published in 1995, anddefines methods of comparing LDSs from different manufacturers. These criteria are defined:

Sensitivity The sensitivity is a composite measure of the size of a leak that a system is capable of detecting, and thetime required for the system to issue an alarm in the event that a leak of that size should occur. PipePatrolE-RTTM typically detects leakage below 1% (relating to nominal flow rate) in less than one minute, resultingin a leak volume that is typically less than 50 litres.

Reliability Reliability is a measure of the ability of a leak detection system to render accurate decisions about thepossible existence of a leak on the pipeline, while operating within an envelope established by the leakdetection system design. It follows that reliability is directly related to the probability of detecting a leak, giventhat a leak does in fact exist, and the probability of incorrectly declaring a leak, given that no leak hasoccurred.

Accuracy Accuracy covers estimation of leak parameters such as leak flow rate, total volume lost, type of fluid lost,

and leak location within the pipeline network. The validity of these leak parameter estimates should be asaccurate as possible.

Robustness Robustness is a measure of the leak detection system’s ability to continue to function and provide usefulinformation even under changing conditions of pipeline operation, or in conditions where data is lost or suspect. A system is considered to be robust if it continues to function under such non-ideal conditions.

9



3 Pressure/Flow Monitoring


A leak changes the hydraulics of the pipeline, and therefore changes flow or pressure readings after some time[Krass/Kittel/Uhde]. Local monitoring of pressure or flow at only one point can therefore provide simple leak detection. It

requires no telemetry, for example to compare flow rate at inlet an outlet, as local monitoring of pressure or flow rate issufficient. It is only useful in steady state conditions, however, and its ability to deal with gas pipelines and multi-productliquid pipelines is extremely limited. It does not provide good sensitivity, and leak localisation is not possible.

3.1 Pressure Monitoring

10

pIf a leak occurs, the pressure in the pipeline will fall by an amount

Δ. As pressure sensors are almost always installed, it

is natural to use them for leak detection. The pressure in the pipeline is simply compared against a lower limit after reaching steady state conditions. When the pressure falls below this lower limit, a leak alarm is raised.

This method is also called Pressure Point Analysis.

3.2 Flow Monitoring

The sensitivity of the pressure monitoring method depends on the leak location. Near the inlet and the outlet of thepipeline a leak leads to little or no change in pressure. This can be compensated by flow monitoring, where the flow ismeasured for change. The two methods can be combined.

3.3 Summary

The following table gives an overview of functionality and requirements (for more details, see Chapter 11).

Method Function

Instrumentation

Complexity Demands

Pressure Monitoring LD 1 x P Low

Flow Monitoring LD 1 x Q Low

Table 3: Functionality and instrumentation of Pressure and Flow Monitoring 2

.

Both methods provide leak detection, but no leak localisation. For pressure monitoring only pressure sensor is required,and for flow monitoring only one flow meter is required. Demands on instrumentation are low.

The possible fields of application are:

Method Appl ication

Medium TRFL

Pumping Dynamics

Pressure Monitoring PC, SC Steady L/G (a) (c)

Flow Monitoring PC Steady L/G (a)

Table 4: Fields of application of Pressure- and Flow Monitoring 3

.

Pressure Monitoring is able to detect leaks in shut-in conditions as well as in pumping conditions. This will be true if thepipeline valves seal tightly enough. In contrast, flow monitoring is only able to detect leaks in pumping conditions. Both

2 LD = Leak detection, P = Pressure sensor, Q = Flow sensor

3 PC = Pumping conditions, SC = Shut-in conditions, L = Liquid, G = Gas






methods are restricted to steady state, as small changes in pressure or flow will cause a false alarm. Either method iscapable of monitoring gas and liquid pipelines. Pressure monitoring meets the following requirements of TRFL:

• TRFL a), one autonomous, continuous working system that can detect leaks in steady state conditions and

• TRFL c), one system to detect leaks in shut-in conditions.

In contrast, flow monitoring only achieves:

• TRFL a), one autonomous, continuous working system that can detect leaks in steady state conditions

The following table lists the associated performance parameters.

Method

SensitivityLeak

Types Alarm Time to Detect Threshold Liquid Gas

Pressure Monitoring High Short Long Both

Flow Monitoring High Short Long Both

Table 5: Performance Parameters of Pressure and Flow Monitoring.

Both methods will work without malfunction if pressure and flow stay constant in daily operation. This is true for someliquid pipelines, but never for gas pipelines.

These simple methods normally do not use statistical methods to prevent false alarms (Chapter 6). The only way to avoidfalse alarms is therefore to set wide alarm limits. This causes a short time to detect a leak within liquid pipelines. In gaspipelines pressure changes are rather slow, so leak detection is slow. Both methods detect sudden leaks as well asgradual leaks of adequate size.



4 Negative Pressure Wave


A sudden leak caused, for example, by careless use of an excavator, leads to a negative pressure wave propagating atthe speed of sound (c ) up- and downstream through the pipeline. Such a wave can be recognised using installed

pressure transmitters, giving a leak alarm. It is also possible to calculate the leak location by timing the arrival of thepressure wave at two or more points on the pipeline (Chapter 7).

4.1 Summary


Method Function

Instrumentation

Complexity Demands

Negative Pressure Wave (no leak location) LD 1 x P Medium

Negative Pressure Wave (with leak location) LD+LL 2 x P Medium

Table 6: Functionality and instrumentation for negative pressure wave 4

.

One pressure transmitter allows leak detection only. At least two transmitters are needed for leak localisation. In either case, the selected transmitters must be capable of detecting rapid changes in pressure.


Method

Appl ication

Medium TRFL

Pumping Dynamics

Negative Pressure Wave (no leak location) PC, SC Steady L (a) (c)

Negative Pressure Wave (with leak location) PC, SC Steady L (a) (c) (e)

Table 7: Fields of application for negative pressure wave5

.

The negative pressure wave method is able to detect leaks in steady state as well as in shut-in condition. It is only ableto detect leaks in steady state conditions, and small variations in pressure can easily lead to false alarms. Negativepressure wave methods are most useful in liquid pipelines, as pressure waves are quickly attenuated in gas pipelines.This technique meets the following TRFL requirements:

• TRFL a), one autonomous, continuous working system that can detect leaks in steady state conditions and


• TRFL e), one system to detect the leak position.

4 LD = Leak detection, LL = Leak location, P = pressure sensor

5 PC = Pumping conditions, SC = Shut-in conditions







Method

SensitivityLeak


Pressure Monitoring High Short Long Sudden

Flow Monitoring High Short Long Sudden

Table 8: Performance Parameters of Negative Pressure Wave

This technique will work without malfunction if pressure and flow stay constant in daily operation, which is true for someliquid pipelines but never for gas pipelines. Statistical methods to prevent false alarms (Chapter 6) normally will not beused. The only way to avoid false alarms is therefore to set wide alarm limits. This causes a short time to detect a leakwithin liquid pipelines. In gas pipelines pressure changes are rather slow, so leak detection is also slow. This methodonly detects sudden leaks of adequate size.



5 Balancing Methods

5 Balancing Methods

5.1 Mass Balance

The mass balance method is based on the equation of conservation of mass. In the steady state, the mass entering aleak-free pipeline (MI) will balance the mass leaving it (MO). In the more general case, the difference in mass at the twoends must be balanced against the change of mass inventory of the pipeline ( ∆Mpipe). Over any given period of time, wecan therefore say

14

pipeO I M M M Δ Δ Δ=−

pipeO I leak M M M M

If there is no leak. In principle, the mass in the pipe depends on the density of the product multiplied by the volume of thepipeline. Both are functions of temperature and pressure and the density is also a function of the composition of theproduct. None of these values is necessarily constant along the pipeline.

Any addition mass imbalance indicates a leak. This can be quantified by rearranging the equation and adding a term for leak mass ( ∆Mleak):

Δ Δ Δ −−=

O I leak M M M

Δ

These equations are valid in any consistent mass units.

5.1.1 Uncompensated mass balance

Supposing that a leak were allowed to continue for a long period, the mass entering and leaving the pipeline wouldincrease indefinitely. The mass inventory of the pipeline, on the other hand, remains within a fixed range – and inreasonably steady conditions that range is quite narrow. ∆M pipe therefore becomes negligible over a sufficiently longperiod, and the equation above reduces to:

Δ Δ−≈

(

Δ

Over a finite period (T ), this equation is an approximation. We must therefore set a detection limit, below which anapparent imbalance may the result of neglecting the inventory. This is the smallest detectable leak rate (γ ). A leak isdeclared if:

) M I O

M T γ Δ − Δ > ⋅

The time period T must be sufficiently long for the flow in and out of the pipeline to be large in comparison with thechange in pipeline inventory. In the following cases, a very large value will be required:

• Start-up of a pipeline

• Change of pressure at inlet or outlet, even the change is small

• Product change

• Most gas pipelines, most of the time




5 Balancing Methods

5.1.2 Compensated mass balance

Unlike the uncompensated mass balance, the compensated mass balance takes account of changes in pipelineinventory. The mass inventory of a short section of pipeline with length ∆s and cross-sectional area A containing aproduct of density ρ is given by:

M A s ρ pipeΔ = ⋅ ⋅ Δ

∫=L

0 pipe ds).s( A)s( M ρ

Both density and pipe area may vary along the pipeline. To calculate the exact inventory of a pipeline of length L, it isnecessary to integrate the density profile:

It is not possible to determine the density profile along the pipeline directly. All practical methods are based on initiallydetermining the temperature and pressure profile, and then applying and equation of state – an equation of state allowsthe density to be calculated as a function of temperature and pressure. For products with multiple components such ascrude oil and natural gas, additional variables such as molecular weight or density at reference conditions are required.

The density of crude oil and common refined products can be calculated according to Manual of Petroleum MeasurementStandards Chapters 10 and 11, also known as [API 2540]. The density of gas can be calculated from pressure ( p),temperature (T ), molecular weight (M ) and compressibility factor (Z ) according to the gas law:

15

ZRT

Mp= ρ

( )The value R is the universal gas constant, equal to J mol K 8.314472 ⋅ . The compressibility factor represents the

deviation of the gas from ideal. For temperature and pressure well below the critical point, it often can be assumed to beclose to unity.

Three main methods are used to determine the pressure and temperature profile:

1. Direct measurement of pressure and temperature. A quantity (n) of pressure ( pi ) and temperature (T i )transmitters must be installed sufficiently closely. The pipeline is then split into segments of known volume V

iΔ

at each transducer pair, and the total inventory calculated using:

( ),1

n

pipe i i i

i

V p T ρ =

= Δ∑ M

2. Determination with the help of a simple, steady state model. In liquid pipelines a linear decrease in pressure can

be assumed along the pipeline6

; temperature of the fluid can be assumed to equal ground temperature for longpipelines.

3. Determination with the help of a Real-Time Transient Model (RTTM). The most accurate method is to use apipeline model that covers transient as well as steady state conditions. This allows the temperature andpressure to be determined at every point – see Chapter 8.

Chapter 9 describes PipePatrol SMB from KROHNE Oil & Gas. PipePatrol SMB is a mass balance system, which offersthe possibility to use one of all introduced methods, a), b), and c), to take account on the change of mass in inventory

Pipe M Δ

in the monitored pipeline.

5.2 Use of volumetric flow meters

It is not always practical to measure the mass flow in and out of the pipeline directly – for example, direct mass metersare only available in a limited range of sizes. It is possible to substitute volumetric flow meters, but the indicated volumeflow must be multiplied by line density to derive the mass. Depending on the application, the options for obtaining densityinclude:

6 This assumes a horizontal pipeline of constant internal roughness and cross-sectional area. Other cases require a modified approach.




5 Balancing Methods

• The density of liquids of known composition can be stored in a lookup table

• The density can be directly measured

• The density for crude oil and its products can be determined with the help of pressure and temperature using [API2540], provided that a reference density is available

• The density of gas can be calculated according to the gas law introduced in the previous section. For pure gas at lowpressure, a very simple approach is possible. For natural gas it will be necessary to measure the molecular weight,for example using a gas chromatograph. At high pressure it will be necessary to calculate the compressibility factor.

Where volumetric flow meters are used, it can be convenient to express the pipeline balance in the form of standardvolume instead of mass. The standard volume (V s) is defined as the mass (M ) divided by the density at standardconditions ( ρs):

16

s

s

M V

ρ =

pltl AsC C V V ××=

The standard density is simply the product density at some fixed and agreed temperature and pressure, such as 1.01325

bar and 15°C. In principle, conversion to standard volume simply involves dividing the mass balance equation by aconstant. The conversion can be more complicated in the case of a multi-product pipeline, where the product enteringthe pipeline can be different from the product leaving it.

For liquids, the standard form of the API equation according to [API 2540] allows standard volume to be derived fromactual volume (V A) using two coefficients:

In this case, the mass flow is apparently bypassed – though it is, in fact, still hidden in the derivation of the coefficients.

M &

Q M &

Q( ),V v&

Figure 1: Calculation of mass flow from volumetric flow




5 Balancing Methods

5.3 Summary

The following table gives an overview of functionality and requirements (for more details, see Chapter 11.

Method Function

Instrumentation

Complexity Demands

Uncompensated mass balance LD 2 x Q High

Compensated mass balanceDirect p and T measurement

LD2 x (Q,P,T)n x (P,T)

High

Compensated mass balanceSteady state model

LD2 x (Q,P,T)

TG High

Compensated mass balanceRTTM

LD2 x (Q,P,T)

TG High

Table 9: Functionality and instrumentation for balancing methods

7

.

All balancing methods require at least two flow meters, one at the inlet, the other at the outlet. They provide leakdetection, but no leak location. When the change in pipeline inventory is compensated, additional pressure andtemperature sensors are also needed. Demands on the accuracy of the flow meters are high, because their error limitsare also the detection limits.


Method

Appl ication

Medium TRFL

Pumping Dynamics

Uncompensated mass balance PC Steady L/G (a)


PCSteady

Low TransientL/G (a)


PCSteady



PCSteady

TransientL/G (a) (b)

Table 10: Fields of application for balancing methods8

.

Balancing methods can be used only in pumping conditions: use in shut-in conditions is not possible. Uncompensatedmass balance is only able to monitor steady state conditions. Compensated mass balance is able to monitor for leaks inthe presence of moderate transients, but the detection time will be increased. Uncompensated mass balance is limited to

liquid pipelines; compensated mass balance can monitor gas pipelines more or less. This technique meets the followingTRFL requirements:

• TRFL a), one autonomous, continuous working system that can detect leaks in steady state conditions.

Only the RTTM-compensated mass balance meets this TRFL requirement:

• TRFL b) one of these systems, or a third one, has to be able to detect leaks in transient conditions.

7 LD = Leak detection, Q = Flow sensor, T= Temperature sensor, P = Pressure sensor, T G = Ground temperature sensor

8 PC = Pumping conditions, L = Liquid, G = gas




5 Balancing Methods



Method

SensitivityLeak


Negative Pressure Wave

Uncompensated mass balance Medium Long Very Long Both


Medium Medium Long Both


Medium Medium Medium Both


Medium Short Short Both

Table 11: Performance parameters for balancing methods.

All balancing methods achieve (using accurate flow meters) a medium detection limit. Uncompensated mass balancehas a long time to detect, while compensation for change of inventory helps to shorten the detection time. RTTM-compensated mass balance shows the best results. Leak detection time is longer for gases because of the dynamicinertia of pressure and flow. All balancing methods detect sudden leaks as well as gradual leaks of adequate size.



6 Statistical Leak Detection Systems

6 Statist ical Leak Detection Systems

Statistical Leak Detection Systems use statistical methods to detect a leak. This leads to the opportunity to optimise thedecision if a leak exists in the sense of chosen statistical parameters. However it makes great demands onmeasurements. They need to be steady state (in a statistical sense) for example. Statistical LDSs have poor sensitivity intransient conditions unless they are adapted, for example using a Real-Time Transient Model

Statistical methods can improve the performance of all leak detection methods introduced in this survey. This chapter describes statistical LDSs based on Uncompensated mass balance, Chapter 5.1.1, because these systems are common.

ATMOS PipeTM from ATMOS International [Zhang] is an example.

Statistical Leak Detection Systems use methods and processes from decision theory [Kay]. The hypothesis-test for leakdetection based on the Uncompensated mass balance, Chapter 5.1.1, uses either a single measurement, or multiplemeasurements made at different times.

M One or more measurements of I O M M Δ = −& & &0 H 1 H

Leak :

leak No:

1

0

H

H

can be used to decide between two hypotheses, and :

( )0| pEvery individual measurement is described by conditional probability density function M H Δ &0 H

( )1|

for hypothesis

(no leak) and M H Δ &1 H for hypothesis (leak). In general a Gaussian distribution is assumed: p

Figure 2: Conditional probability density functions

M To assign a single measurement Δ &0 H 1 H

0

1

: No leak

: Leak

H M

H

γ

γ

≤ ⇒⎧Δ ⎨

> ⇒⎩

&

to one of the both hypothesis and , an alarm limit γ is defined. The test

than is defined as follows:

6.1 Probabil ity Ratio Test

The art of the Probability Ratio Test is to choose a value of γ so that:

( )e min→ ), and0| truFAP P M H γ = Δ >• No false alarm is given under leak free conditions (





• An alarm is always given under leak conditions ( ( )1| true min M P P M H γ = Δ ≤ → )

This problem is solved throughout the family of Probability-Ratio-Tests. Details can be found in [Kroschel] for example.

6.2 Sequential Probabil ity Ratio Test (SPRT)

M ΔThe Probability Ratio Test bases its classification result on one single measurement & . Statistical methods are morepowerful when testing a whole collection of data:

N 1 M M &K&& ΔΔΔ =M

ΔM& ( )0|

pThe characteristic of the collection of data is described by the conditional probability density function H ΔM&

( )1|

for hypotheses (no leak) and H ΔM& 1 H 0 H p for hypotheses (leak). [Wald] published the Sequential Probability

Ratio Test (SPRT) in the early 40’s, which leads to a recursive algorithm that can be used for online-testing.

6.3 Summary


Method Function

Instrumentation

Complexity Demands

Statistical LDS

Uncompensated mass balance LD 2 x Q Medium

Table 12: Functional summary of statistical LDSs9

.

Statistical methods need two flow meters at least, one at the inlet, the other one at the outlet. They provide leakdetection, but no leak location. The use of statistical methods can reduce the demands on accuracy of the flow meters.

Possible fields of application are:

Method

Appl ication

Medium TRFL

Pumping Dynamics

Statistical LDS

Uncompensated mass balance PCSteady


Table 13: Fields of application for statistical LDSs10

.

Statistical LDSs can be used in pumping conditions, but not under shut-in conditions. Statistical LDSs are able to operatein moderate transient conditions, but with increased leak detection time. Statistical LDS provides moderate performanceon gas pipelines. They tick the following boxes:

• TRFL a), one autonomous, continuous working system that can detect leaks in steady state conditions.


9 LD = Leak detection

10 PC = Pumping conditions






Method

SensitivityLeak


Statistical LDS

Uncompensated mass balance Low Long Very Long Both

Table 14: Performance parameters for statistical LDSs.

Statistical LDS have are very sensitive with a low alarm limit, but time to detect is rather long. Statistical methods detectsudden leaks as well as gradual leaks of adequate size.



7 Leak Location

7 Leak Location

When a leak is detected, i t is important to locate it. An exact leak location gives the opportunity to take swift containingaction to minimise harm to people and the environment. Localilsed repairs can then be carried out cost-effectively.

7.1 Gradient Intersect ion Method

The gradient intersection method is based on the fact that the pressure profile along the pipeline with its length L willchange significantly if a leak occurs.

I V & OV &dt

dV Leak

Figure 3: Leak location by gradient intersection method

Pressure drop in a leak free pipeline is linear 11

(dashed, green line in Figure 3). If a leak occurs, the pressure profiledevelops a kink at the leak point – (continuous, red line). The leak location can be determined by calculating theintersection point of the pressure profiles upstream and downstream of the leak. The classic gradient intersectionapproach calculates the gradient of both lines using two pressure readings near the inlet and two pressure readings near the outlet. The model-based gradient intersection method as used by PipePatrol E-RTTM LDS Chapter 10, calculates thetwo gradients with the help of the real time transient model, computed by flow and pressure measurements at in- and

outlet.

Direct use of pressure measurements achieves accurate results, but only if pipeline is in steady state. The origin or development of the leak (sudden or gradual) does not matter. PipePatrol E-RTTM uses the RTTM based gradientintersection method, which compensates transients leading to good results even under highly transient conditions.

7.2 Wave Propagation Method

A sudden leak caused, for example, by careless use of an excavator, leads to a negative pressure wave propagating atthe speed of sound (c) up- and downstream through the pipeline of given length (L). Such a wave can be recognised

using installed pressure transmitters, giving a leak alarm. The leak position can be determined12

if the moment

(downstream) and (upstream), when this negative wave passes the transmitters is measured. Setting ,

the leak location is:

downt

upt down upt t t Δ = −

22

( )1

ˆ2

Leak s L c t = ⋅ − ⋅ Δ

The wave propagation method needs an identifiable negative pressure wave. Results will be good, if a leak is sufficientlylarge and sudden. Small and/or gradual leaks cannot be located by this method. In practical use, it is limited to steadystate conditions. It is able to locate leaks in pumping or in shut-in conditions. PipePatrol E-RTTM uses the RTTM basedgradient intersection method, which compensates transients leading to good results even under highly transientconditions..

11

This is true for liquid pipelines with constant local wall friction coefficient k R, a constant cross-section A, and a horizontal built pipeline.The method must be slightly modified in other cases.

12 The speed of sound is not constant in liquid pipelines under multi-product condition or in gas pipelines. The method has to be modifiedslightly.




8 RTTM – Real Time Transient Model


RTTM means “Real-Time Transient Model”. Some LDSs of the PipePatrol-LDS-Family by KROHNE Oil & Gas are basedon RTTM, also known as the “Pipeline Observer”. Chapter 9 introduces PipePatrol Statistical Mass Balance (SMB), amass balance system using RTTM for calculating the change in inventory. It also uses statistical methods introduced inChapter 6. The KROHNE “flagship” is PipePatrol Extended Real-Time Transient Model (E-RTTM), which combinesRTTM technology used for the residual-method (Chapter 8.2) with leak signature analysis to prevent false alarms,Chapter 10.

RTTM systems build mathematical models of the flow within a pipeline using basic physical laws such as:

• Conservation of mass

• Conservation of momentum

• Conservation of energy

When combined with an equation of state, introduced in Chapter 5, RTTM systems easily model transient and steadystate flow in a pipeline. A transient state means a large change in short time, so flow, pressure, temperature and density

may all change rapidly. The changes propagate like waves through the pipeline with the speed of sound (c ) of the fluid.Transient state conditions occur in a pipeline for example:

• At start-up

• If the pressure at inlet or outlet changes, even the change is small

• When a batch changes or when multiple products are in the pipeline

Gas pipelines are almost always in transient conditions, because gases are very compressible. Even in liquid pipelinestransient effects cannot be disregarded.

An RTTM makes it possible to calculate mass flow, pressure, density and temperature at every point along the pipeline inreal-time with the help of mathematical algorithms. These solutions are called local profiles. The outputs of the RTTM are

shown in the diagrams that follow using the format: ( )s p̂ , for example. The "^" is used to indicate that the values are not

measured, but calculated. The addition of (s) indicates that these are not simple point values, but profiles and thereforefunctions of the distance along the pipeline (s).

Calculation of the local profiles needs process measurements at the inlet (subscript I) and outlet (subscript O) of thepipeline – these points are known together as the “head stations”. Various combinations of measurement are possible,as we shall see in a moment. A value of ground temperature, TG is also needed, assuming that the pipeline isunderground. As it does not vary much along a pipeline in practice, one sensor is used to measure a representative"assumed constant" value.





The simplest and lowest-cost possibility for RTTM is shown in Figure 4. In this case only temperature and pressure atthe head stations are fed into the RTTM, along with ground temperature.

F P T T

RTTM (Pipeline Observer)

T P F

P I

Temperature (T) of Ground

Temperature (T) of Fluid

Pressure (P)

Flow (F)

Inlet Outlet

T F,I T G,I->O T F,O PO

( )ˆ M s& ( )ˆ p s ( )ˆ s ρ ( )T̂ s

Figure 4: RTTM to calculate local profiles; model using pressure readings

13

It is also possible to implement the model using flow at the head stations instead of pressure:

F P T


T P F

Temperature (T) of Ground

Temperature (T) of Fluid

Pressure (P)

Flow (F)

Inlet Outlet

T F,I T F,O

( )ˆ M s& ( )ˆ p s ( )ˆ s ρ ( )T̂ s

I v Ov

T

T G,I->O

Figure 5: RTTM to calculate local profiles; model using flow readings14

Especially in shut-in conditions (chapter 10) this method of RTTM is used.

13 Subscripts are used as follows: "I" = inlet, "O" = outlet, "G" = ground

14 The RTTM is needs the flow as a velocity v in m/s. Usually, flow is given in terms of mass or volume flow, so velocity has to becalculated. Details can be found in section 8.4





Compensation Approach

It was mentioned in 5.1.2 that a compensated mass balance calculation needs to integrate the density (ρ) at every pointalong the pipeline in order to determine the mass inventory of the pipe. The RTTM provides the necessary information todo so accurately, as shown in Figure 6.

F P T


T P F

P I

Inlet

T F,I T F,O PO

I M &

O M &

Outlet

ˆPipe M

( ) ( )0

L

A s s ds ρ ⋅∫

d/dt

ˆPipedM dt

Line Pack Compensation

( )ˆ s ρ

+ --

ˆ Leak

M M Δ =& &

T

T G,I->O

Figure 6: Compensated mass balance with RTTM based compensation

15

In this implementation, the RTTM calculates the density profile based on pressure and temperature at the head stations.Independent flow measurements at the head stations are combined with the calculated pipeline inventory to perform acomplete mass balance.

PipePatrol Statistical Mass Balance (SMB) (Chapter 9) combines the mass balance with statistical methods (Chapter 6)and RTTM-technology.

15 The flow needs to be mass flow here; if volume flow given, mass flow has to be calculated – see chapter 5.2





Head Stations Residual or Differential Approach

The flow at head stations in Figure 7 is not necessary to calculate the local profiles, as pressure is used for thispurpose. The RTTM calculates flow at the end points of the pipe as well as everywhere else. It is therefore possiblecheck the difference between measured and calculated flow. A difference between the two indicates a change in the

dynamics of the pipeline – in other words, a suspicion that there may be a leak.

F P T

RTTM (no leak) = Pipeline Observer

T P F

P I

Inlet

T F,I T F,O PO

I M &ˆ

I M

x y

Flow-Residuals

- - O M &

ˆO

M

Outlet

T

T G,I->O

Figure 7: Residual or differential approach for head station monitoring

16

Both of the Flow-Residuals can be used as leak indicators

ˆ

ˆ I I

O O

x M M

y M M

≡ −

≡ −

& &

& &

The no-leak hypothesis H0 is true if the indicated flows agree sufficiently closely with the model. The leak-presenthypothesis H1 is true if there is a positive residual at the inlet and/or a negative residual at the outlet. Mathematically:

0

1

: No leak 0, 0

: Leak 0, 0

H x y

H x y

⇒ ≈ ≈

⇒ > <

We insist on the appropriate signs for the residuals because a positive residual at the outlet, for example, would indicatethat more fluid was leaving the pipeline than expected. In other words, the cases x < 0 and y > 0 would indicate a“negative leak”. This tells us something interesting about the performance of the meters or the validity of the RTTM, but itis not a physically realistic basis for declaring a leak alarm.

PipePatrol E-RTTM (Chapter 10) uses this technology together with statistical methods (Chapter 6) and RTTM-technology.

16 The flow here needs to be mass; if volume flow given, mass flow has to be calculated – see section 5.2.





Fundamentals of Leak Detection KROHNE Oil &

Substations Residual o r Differential Approach

If a pipeline is long enough, substations with pressure sensors will often be included. The indicated pressures can becompared with those calculated using the RTTM method, giving pressure residuals as follows:

Gas 27

ˆ , 1 z p p i n= − ≤ ≤i i i

A significant residual leads to a suspicion of a leak, although “negative leaks” are once again ignored for the purposes of leak monitoring.

1ˆ p1 p 2

ˆ p 2 p

Figure 8: Residual or differential approach for pressure substation

17

18

Note that temperature and flow measurement at the substations are unnecessary.

8.1 Flow Calculation

Flow Q can be expressed in three ways:

• Mass flow M

& e.g. in kg/s or t /h is needed for Line-Pack-Compensation (Figure 5

) or flow-residuals (Figure 6

).

• Volume flow V & e.g. in m3/s or m3/h.

• Flow velocity v in m/s. This way is needed for RTTM as shown in Figure 4.

M A V A v= ρ ⋅ = ⋅ ⋅& & , where A is the cross section of the pipeline in m2 andThe relation between those values is given by

ρ the density of the fluid in kg/m3. Three options for calculating density have already been presented in Chapter 5.2.

17

For a better point of view only two substations are shown. The method is able to handle as much substation as present at the pipeline.18

P-substations provide pressure readings; P,T-substations provide temperature readings in addition; P,T,F-substations provide flow readings in addition.



9 PipePatrol Statistical Mass Balance (SMB)

9 PipePatrol Statist ical Mass Balance (SMB)

PipePatrol Statistical Mass Balance (SMB) combines mass balance with statistical methods (Chapter 6) and RTTM-technology (chapter 8). Figure 9 presents an overview.

F P T

Line Pack Compensation• Without compensation• Using measured p and T along the pipeline• Using stationary model• Using RTTM

T P F

P I

Inlet

T F,I T F,O PO

I M &

O M &

Outlet

ˆPipedM dt

+ --

M Δ &

Leak Classification

Classification:- Leak yes/no- if yes: leak flow

T

T G,I->O

Q

M &

Q

M &

Figure 9: Functionality of PipePatrol SMB

19

The estimated leak rate is analysed by a statistical leak classifier. This reliably prevents false alarms. Line packcompensation is possible with any of those methods presented in Chapter 5.1.2. Leak classification provides thefollowing advantages:

• Minimum probability of a false alarm ( minFA → )P

• Maximum probability of giving an alarm in leak conditions ( min M P → )

9.1 Summary

An overview of functionality and requirements is given in the following table (functionality and requirements incomparison to the other, introduced methods will be summarized in Chapter 11).

Method Function

Instrumentation

Complexity Demands

PipePatrol SMB

PipePatrol SMBuncompensated

LD 2 x Q Medium

PipePatrol SMBwith direct P and T compensation

LD2 x (Q,P,T)n x (P,T)

Medium

High20

PipePatrol SMBwith steady state model

LD2 x (Q,P,T)

TG Medium

High20

PipePatrol SMBwith RTTM

LD2 x (Q,P,T)

TG MediumHigh20

Table 15: Functionality and instrumentation of PipePatrol SMB21

.

19 The transformation of the volume flow Q to mass flow is done within PipePatrol, see chapter 5.2.

20 Medium when meeting TRFL (a), high when meeting TRFL (d)





All balancing methods need at least two flow meters, one at the inlet and the other at the outlet. They provide leakdetection, but no leak location. If the change in pipeline inventory is compensated, the compensation method definesadditional instrumentation such as pressure and temperature sensors.

If PipePatrol SMB is combined with highly accurate flow meters, it can detect gradual leaks according to TRFL d). Theaccuracy requirement on the flow can be reduced if all that is required is an autonomous, continuously operating systemthat can detect leaks within steady state conditions. These demands are lower than when statistical methods are notused.


Method

Appl ication

Medium TRFL

Pumping Dynamics

PipePatrol SMB


PCSteady


PipePatrol SMBwith direct P and T compensation PC SteadyLow Transient L/G (a) (d)


PCSteady

Low TransientL/G (a) (d)


PCSteady

TransientL/G (a) (b) (d)

Table 16: Possible fields of application of PipePatrol SMB22

.

All versions of PipePatrol-SMB can be used in pumping conditions, but use under shut-in conditions is not possible. Allversions of PipePatrol SMB are capable of handling low transient conditions, even on gas pipelines. PipePatrol SMBbased on RTTM technology is able to monitor in heavily transient conditions, for example start up and shutdownconditions, and shows outstanding performance on gas pipelines. All versions of PipePatrol SMB are capable of offering:

• TRFL a), an autonomous, continuous working system, which can detect leaks within steady state conditions.

If pipeline inventory compensation is used and the flow meters are accurate, PipePatrol SMB is also able to offer:

• TRFL d), a system to detect gradual leaks.

PipePatrol SMB combined with RTTM technology additionally offers:

• TRFL c), a system able to detect leaks in transient conditions.

21 LD = Leak Detection, LL = Leak Location.

22 PC = Pumping Conditions, SC = Shut-in Conditions.






The following table lists the associated performance parameters. As the performance varies according to whether gradual leak detection is required, two sets of sensitivity requirements are given in some cases:

Method

T

RF L

Sensitivity

LeakTypes Alarm Time to Detect Threshold Liquid Gas

PipePatrol SMB


Low Long Very Long Both

PipePatrol SMBwith direct P and T compensation

(a) Low Medium LongBoth

(d) Very low Long Very Long


(a) Low Medium LongBoth



(a) Low Short MediumBoth

(d) Very low Medium Long

Table 17: Performance parameters of PipePatrol SMB.

All versions of PipePatrol-SMB offer (very) sensitive alarming thresholds. Time to detect a leak is long without pipelineinventory compensation, but shortens significantly if it is available. Use of highly accurate flow meters enables detectionof gradual leaks – in which case very sensitive alarming thresholds are possible, but time to detect a leak will rise. Timeto detect a leak is longer for gas pipelines because of the dynamic inertia of pressure and flow. All versions of PipePatrol-SMB detect both sudden and gradual leaks of sufficient size.



10 PipePatrol Extended Real-Time Transient Model (E-RTTM)


PipePatrol E-RTTM is KROHNE’s flagship LDS, which fuses the RTTM technology described in chapter 8 with leaksignature analysis described in chapter 10.1 in a unique manner. For this reason it is called “Extended RTTM”

[Geiger/Werner/Matko]. PipePatrol E-RTTM is able to monitor pipelines in pumping conditions (PipePatrol E-RTTM/PC,Pumping Condition) and in shut-in conditions (PipePatrol E-RTTM/SC, Stand-still Condition or Shut-In Condition).

10.1 Leak Signature Analysis

An LDS that generate false alarms cannot be trusted, so it is a key task to eliminate them. PipePatrol E-RTTM uses leaksignature analysis, which executes after the pipeline observer, to prevent them. In this second stage residuals areanalysed for leak signatures:

• Sudden leak. This “classical leak” develops quickly by external damage of the pipeline. It causes a dynamic signaturein residuals. When such a leak recognised, a leak alarm will be reported and the leak location and leak flow aredetermined.

• Sensor drift or gradual leak. These may occur by contamination of the flow meter or by small leaks caused by

corrosion. They result in indistinguishable, slow signatures. When drift is recognized, a sensor alarm is reported andthe apparent leak flow is determined.

This boosts the reliability and the robustness of the system without compromise to sensitivity and accuracy. False alarmsare prevented, even with low alarm thresholds.

10.2 Leak Location

PipePatrol E-RTTM locates leaks using two methods, both introduced in chapter 7:

• Model-based gradient intersection method

• Model-based wave propagation method

The model-based gradient intersection method ([Billmann]) is calculated using the mass residuals at the head station ( x,y ). For a pipeline of length L:

31

̂Leak

y z L

x y

−= ⋅

−

down up

down upt t t Δ = −

The model based wave propagation method analyses residuals x and y for the appearance of a step. If a step isrecognized downstream at time t in y, and recognized upstream at time t in x, the leak location can be determined

by the runtime difference :

( )1

ˆ

2

Leak s L c t = ⋅ − ⋅ Δ





10.3 PipePatro l E-RTTM/PC – Leak Detection in Pumping Condit ion

10.3.1 Head stations monitoring

F P T


T P F

P I

Inlet Outlet

T F,I T F,O PO

I M & - -

ˆ I

M &

O M &

Leak Signature Analysis(Head-End Station)

Leak-Alarm Leak flow and location

Leak Signatures

x y

Sensor-Alarm

ˆO M &

T

T G,I->O

Q

M &

Q

M &

Figure 10: PipePatrol E-RTTM/PC: pumping conditions, head station monitoring

23

The example in Figure 10 shows head station monitoring based on the residual approach described in chapter 8.2. Withthe help of the RTTM, PipePatrol E-RTTM compares the measured flow at inlet and outlet with the calculated flowassuming a leak free pipeline. The flow residuals, which are used by the leak signature analysis, are:

ˆ ˆ x

32

I I O O M M y M M ≡ − ≡ −& & & &

Use of the RTTM Pipeline Observer compensates the transient behaviour of the pipeline. Even under heavy transientconditions (for example during pipeline start-up) residuals stay close to zero in leak-free conditions. Sensitive leakdetection is therefore possible in transient conditions

The dynamic-free residuals are now passed to the second stage, the leak signature analysis. Its tasks according toChapter 10.1 and 10.2 are to:

• Manage alarms

• Determine leak rate and leak location.

23 The transformation of the volume flow Q to mass flow is done within PipePatrol, see Chapter 8





10.3.2 Substation monitoring without flow measurement

F P T


T P F

P I

Inlet

T F,I T F,O PO

P P

- -1

ˆ p1 p

2ˆ p

2 p

Substation 1 Substation 2 Outlet

Section 1->2Section I->1 Section 2->O

Leak Signature Analysis(Substation 1)

Leak Signature Analysis(Substation 2)

Substation Evaluation

Leak-Alarms Section (i)->(i+1) Leak flow and location

z1 z2

Sensor-Alarms Section (i)->(i+1)

T

T G,I->O

Leak Signatures

Leak Signatures

Figure 11: P ipePatrol E-RTTM/PC: pumping conditions, pressure at substations (Substation monitoring without flow by pressure

residuals)24

.

The example in Figure 11 shows a pipeline with pressure measurement at substations, an idea already introduced inSection 8.3. The RTTM Pipeline Observer uses pressure and temperature sensors at the head stations to calculate thelocal profiles, including the pressure profile along the pipe. Any discrepancy between the calculated and the observedpressure at the substations indicates a change in the pipeline dynamics: in other words, a leak. The pressure residual ateach station is:

ˆ , 1i i i z p p i n= − ≤ ≤

These are used by the leak signature analysis to detect a leak and find its location. This kind of pipeline monitoring iscalled substation monitoring. The Pipeline Observer compensates for any transient behaviour of the pipeline.

The compensated residuals are now passed to the second stage, the leak signature analysis. Its task is to managealarms for each individual substation. Results of leak signature analysis are combined in a Substation Evaluation stage,which groups substation alarms and determines leak flow rate and leak location.

24 Two substations are shown for clarity. The method is able to handle any number of substations





10.3.3 Segment monitoring for substations with flow measurement

I M &

( 1)

1

ˆ I M →& (1 2 )

1

ˆ M

→& (1 2 )

2

ˆ M

→&( 1)ˆ I

I M →& (2 )

2

ˆ O M

→& (2 )ˆ O

O M →&

I M & O M &

1 M &2 M &

Q

M &

Q

M &

Q

M &

Q

M &

Figure 12: PipePatrol E-RTTM/PC: pumping conditions, PTF substations (segment monitoring by measured flow with flow residuals)

25

.

The example in Figure 12 shows a special case where flow measurement is available at substations in addition topressure and temperature. This configuration permits Segment Monitoring , where the pipeline is split into independentsegments as shown in the diagram. Only two substations are shown for clarity, but the method can be scaled to cover asmany as required.

Independent RTTM Pipeline Observers and E-RTTM Leak Classifiers may be applied in parallel to every segment, eachusing the methods already introduced in earlier sections. The shorter length of the monitored sections compared to theoverall length of the pipeline leads to several advantages:

• Significantly lower smallest detectable leak rate

• Significantly shorter time to detect a leak

• Significant improvement in accuracy of leak location

The Segment Evaluation chooses the segment that shows the most significant leak signature, determines whether a leakalarm or a sensor alarm is present, and reports the leak location and flow if appropriate.

This method achieves better performance then the method shown in Figure 11, especially on gas pipelines. Thedisadvantage is the complex instrumentation needed at the substations.

KROHNE Oil and Gas is able to configure this method to assign pipeline segments dynamically. For example, in theevent of a transmitter failure at substation 1 it is possible to skip this station and perform leak detection between the inletstation and substation 2.

25 Ground temperature is omitted for clarity





10.3.4 Leak detection with substations and virtual flow monitoring

I M &

( 1)

1

ˆ I M

→&(1 2 )

1

ˆ M

→& (1 2 )

2

ˆ M

→&( 1)ˆ I

I M →&

(2 )

2

ˆ O M

→&(2 )ˆ O

O M →&

I M &

O M &

Q

M &Q

M &

Figure 13: PipePatrol E-RTTM/PC: pumping conditions, PT substations (segment monitoring by virtual flow with flow residuals).

The disadvantage of the complex and expensive instrumentation from chapter 10.3.3 can be eliminated by the virtualflow measurement, as shown in Figure 13. The functionality is nearly the same as shown in Figure 12, except thatdirect flow measurement is replaced by values calculated in the RTTM Pipeline Observer.

Each RTTM Pipeline Observer calculates flow at every point along its associated segment, including the inlet and theoutlet. The measured flow at the head stations is compared with the calculated flow in the usual way. At intermediatestations, the calculated outlet flow for the section upstream is simply compared with the calculated inlet flow for thesection downstream.

This method has no significant disadvantages compared to real flow measurement at intermediate stations. As only oneRTTM Pipeline Observer calculates the flow at the head stations, a real flow measurement is still needed at theselocations for comparison.





I M &

( 1)

1

ˆ I M →&(1 2 )

1

ˆ M

→& (1 2 )

2

ˆ M

→&( 1)ˆ I

I M →&

(2 )

2

ˆ O M

→&(2 )ˆ O

O M →&

O M &

Q

M &Q

M &

Figure 14: PipePatrol E-RTTM/PC: pumping conditions, P substations (segment monitoring by virtual flow with flow residuals).

It is possible to take this approach even further. Figure 14 shows a pipeline with only pressure sensors at thesubstations. The functionality of configuration is nearly the same as shown in Figure 13, except that the temperature atsubstations is now calculated by an additional single RTTM Pipeline Observer.

This single RTTM Pipeline Observer calculates temperature profile along the entire pipeline, using inputs from the headstations. In leak-free conditions, this gives exact temperature values at every substation. In case of a leak, the dynamicsof the pipeline are disturbed so in principle the calculated temperature values will show an error. As leak flow has li ttleeffect on pipeline temperature, these errors are negligible in practice.

Using an RTTM Pipeline Observer, it is therefore possible not only to eliminate flow measurement at substations buttemperature measurements also. This is highly advantageous, as all intrusive process measurements are noweliminated. With the KROHNE Oil and Gas E-RTTM model, it is therefore possible to realise the advantages of Substation Leak Monitoring without compromising the ability to pig the pipeline from end to end.





10.4 PipePatro l E-RTTM/SC – Leak Detection in Shut-in Conditions

PipePatrol E-RTTM/SC is the abbreviated form of PipePatrol E-RTTM/Stand-Still or Shut-In Conditions. A model-based

pressure-temperature method is used, which is valid for both liquid and gas pipelines. In shut-in conditions the pipeline ispressurised using pumps and valves, the fluid is sealed in the pipeline, and the pressure is monitored. The relevantvalves must be leak-tight, and this should be considered when choosing them.

10.4.1 Head Station Monitoring

Inlet Outlet

37

F P T


T P F

T F,I T F,O

0 I M =&

- - ̂I p

0O

M =&

Leak Signature Analysis(Head-End Station)

Leak-Alarm Leak flow and location

Leak Signatures

z I zO

Sensor-Alarm

ˆO p

I p O p

T

T G,I->O

Figure 15: PipePatrol E-RTTM/SC: shut-in conditions, no substations - Head station monitoring

The simple case in Figure 15 shows leak monitoring in shut-in conditions. It is possible to deduce even without directmeasurement that the flow at the inlet and outlet should be zero. The RTTM Pipeline Observer can use this to calculatethe local profiles, including the expected pressure at the two head stations. It is possible to compare these with themeasured values, giving pressure residuals zI and zO:

ˆ ˆ I I I O O O z p p z p p= − = −

The RTTM Pipeline Observer is able to compensate transient behaviour of the pipeline in shut-in conditions. In addition,the equation of state in the RTTM compensates for temperature influence on pressure.

The compensated residuals are passed to the E-RTTM Leak Signature Analysis, as introduced in chapter 10.3. Leak rateand leak location will be determined when necessary.





0 I M =&

1ˆ p1 p 2

ˆ p2 p

0O M =&

I p O

pˆO

pˆ I

p

Figure 16: PipePatrol E-RTTM/SC: shut-in condition, P substations

(Substation monitoring with pressure residuals)26

.

Figure 16 shows a pipeline with substations. The pressure profile for the entire pipe is calculated using one RTTMPipeline Observer. Calculated pressures can then be compared with measured values at the head stations and thesubstations.

If the relevant valves are completely leak tight, even very small, gradual leaks will be recognised. In this case, PipePatrolE-RTTM/SC meets the requirements of TRFL (d).

26 Only two substations are shown for clarity. The method is able to handle as many substations as required.





Summary

An overview of functionality and requirements is given in the following table (see Chapter 11 for more details).

Method Function

Instrumentation

Complexity Demands

PipePatrol E-RTTM, KROHNE Oil & Gas

PipePatrol E-RTTM/PCHead station monitoring

LD+LL2 x (Q,P,T)TG

Medium

PipePatrol E-RTTM/PCSubstation monitoring

LD+LL2 x (Q,P,T)TG n x P

Medium

PipePatrol E-RTTM/PCSegment monitoring

LD+LL2 x (Q,P,T) TG

n x (Q,P,T)Medium

PipePatrol E-RTTM/PCSegment monitoring by virtual flow

LD+LL2 x (Q,P,T) TG

n x PMedium

PipePatrol E-RTTM/SCHead station monitoring

LD+LL 2 x (P,T)TG

Medium

PipePatrol E-RTTM/SCSubstation monitoring

LD+LL2 x (P,T)TG n x P

Medium

Table 18: Functionality and instrumentation of PipePatrol E-RTTM 27

.

All versions of PipePatrol-E-RTTM in pumping conditions (PipePatrol E-RTTM/PC) need measurements of flow,temperature and pressure at the head stations. Ground temperature is reasonably constant along the pipeline, so asingle representative measurement at some point along the pipeline is sufficient. All versions of PipePatrol-E-RTTM inshut-in conditions (PipePatrol E-RTTM/SC) need measurements of temperature and pressure at the head stations.

PipePatrol-E-RTTM provides leak detection and leak location in both pumping condition and shut-in condition. Use of statistical methods reduces the demands on instrumentation to medium. In particular, the absolute accuracy of theinstruments does not matter.

Possible fields of application are:

Method

Appl ication

Medium TRFL

Pumping Dynamics


PCSteady

TransientL/G (a) (b) (e)


PCSteady


PipePatrol E-RTTM/PCSegment monitoring PC SteadyTransient L/G (a) (b) (e)

PipePatrol E-RTTM/PCSegment monitoring by virtual flow

PCSteady



SCSteady

TransientL/G (c) (d) (e)


SCSteady

TransientL/G (c) (d) (e)

Table 19: Possible fields of application of PipePatrol E-RTTM 28

.

27 LD = Leak Detection, LL = Leak Location.

28 PC = Pumping Conditions, SC = Shut-in Conditions.






PipePatrol E-RTTM/PC provides leak detection in pumping conditions; PipePatrol E-RTTM/SC provides leak detection inshut-in conditions. All versions are able to monitor steady state, and transient conditions. Even gas pipelines can bemonitored without problems.

PipePatrol E-RTTM/PC performs the following functions:

• TRFL a), one autonomous, continuous working systems, which can detect leaks within steady state conditions

• TRFL b), one of these systems, or a third one, has to be able to detect leaks in transient conditions


PipePatrol E-RTTM/SC performs the following functions:


• TRFL d), one system to detect gradual leaks,



Method

T RF L

SensitivityLeakTypes Alarm Time to Detect

Threshold Liquid Gas


Low Very short Medium Both


Low Very short Long Both

PipePatrol E-RTTM/PCSegment monitoring

Low Very short Short Both

PipePatrol E-RTTM/PCSegment monitoring by virtual flow Low Very short Short Both


(c) Low Short LongBoth



(c) Low Short LongBoth


Table 20: Performance parameters of PipePatrol E-RTTM.

All versions of PipePatrol-E-RTTM provide a sensitive alarm threshold, PipePatrol E-RTTM/SC even a very sensitivealarming threshold if required. PipePatrol E-RTTM/PC provides very short times to detect a leak for liquid pipelines. Timeto detect a leak becomes longer for gas pipelines because of the dynamic inertia of the fluid. Instead of substationmonitoring, section monitoring should be used here, because it is much faster. If PipePatrol E-RTTM/SC is used todetect very slow gradual leaks, time to detect a leak will raise.

All versions of PipePatrol-E-RTTM are able to detect and locate sudden leaks as well as gradual leaks of sufficient size.



Bibliography

Bibliography

[API 1130] API 1130: Computational Pipeline Monitoring for Liquid Pipelines. American PetroleumInstitute, 2002.

[API 1155] API 1155: Evaluation Methodology for Software Based Leak Detection Systems. American Petroleum Institute, 1995.

[API 2540] API 2540: Volume Correction Factors. American Petroleum Institute, 2002.

[Baehr] Baehr, H. D.: Thermodynamik. Springer, 1996.

[Billmann] Billmann, L.: Methoden zur Lecküberwachung und Regelung von Gasfernleitungen.Fortschrittsberichte VDI Reihe 8, VDI-Verlag.

[Bohl] Bohl, W.: Technische Strömungslehre. Vogel-Verlag, 12. Auflage, 2002.

[Geiger/Werner/Matko] Geiger, G., Werner, T., Matko, D.: Leak Detection and Locating – A Survey. 35th Annual PSIG Meeting, 15 October – 17 October 2003, Bern, Switzerland.

[Hancock] Hancock, John C.; Wintz, Paul A.: Signal Detection Theory. McGraw Hill, 1966.

[Kay] Kay, Steven M.: Fundamentals of Statistical Signal Processing, Volume 2. PrenticeHall, 1998.

[Krass/Kittel/Uhde] Krass, W., Kittel, A., Uhde, A.: Pipelinetechnik. Verlag TÜV Rheinland, 1979.

[Kroschel] Kroschel, K.: Statistische Nachrichtentheorie. Springer-Verlag, 1996.

[RFVO] Rohrfernleitungsverordnung. In TRFL - Technische Regeln für Fernleitungen. Carl-Heymanns-Verlag, 2003.

[TRFL] TRFL - Technische Regeln für Fernleitungen. Carl-Heymanns-Verlag, 2003.

[Wald] Wald, A.: Sequential Analysis, John Wiley and Sons, New York, 1947.

[Zhang] Zhang, X. J.: Statistical Leak Detection in Gas and Liquid Pipelines. Pipes & PipelinesInternational, July – August 1993, p. 26 – 29.




Definitions

Definitions

Accuracy Criterion of API 1155. This especially concerns leak location: details of the leak location

must be accurate. API 1130 Computational Pipeline Monitoring for Liquid Pipelines, American Petroleum Institute.Covers Design, Implementation, Test and processing of .

API 1155 Evaluation Methodology for Software Based Leak Detection Systems, AmericanPetroleum Institute. Helps to compare different ldss. Defines Sensitivity, Reliability,

Accuracy and Robustness. API 2540 Volume Correction Factors, American Petroleum Institute. Describes relations to calculate

density of common crude oil and its products (such as gasoline) from temperature andpressure.

Balancing Methods Also Mass Balance. Ldss that use the conservation of mass for leak detection. These arecompensated and uncompensated Mass Balance as well (e.g. PipePatrol SMB), In thebroader sense also RTTM- and E-RTTM-Systems as PipePatrol E-RTTM.

Batch-Separation-Pig Device to separate batches from each other in multi-product pipeline. Coefficient of

Compressibilit y (z)

Dimensionless coefficient representing the departure of a gas from “ideal” behaviour. Acoefficient of one indicates ideal behaviour.

Compressibility Attribute of a liquid, representing the rate of change of density with respect to pressure. Itis compensated by (e)-rttm-systems.

CPM System Computational Pipeline Monitoring systemGradual Leak A slowly developing leak, often with a very low Leak rate. TRFL demands special

Systems to detect gradual leaksDensity Meter A sensor that monitors the actual density of a fluidDetection Li mit Theoretical Value of the smallest, detectable leak rate.Difference Method Synonym for: Residual MethodDRAG Drag Reducing Agent. Added to liquids to reduce pipe wall frictionDrift Very low frequency disturbance in measurements.Error threshold Maximal or guaranteed difference of a measured value from its true value. E-RTTM-System LDS based on Extended RTTM-Technology. This technology combines RTTM-

Technology with the Leak signature analysis.False Alarm A leak alarm that is raised when no real leak is presentFlexibility An attribute of the wall for a pipeline, representing the rate of change of cross section with

respect to pressure. Can be compensated by (e)-rttm-systemsFlow Monitoring A simple LDS, where flow is measured at one single location at the pipeline; flow changes

in case of a leak. Method is out of date.Flow Collective term for mass flow (e.g. In kg/s), volume flow (e.g. In m 3/h), and velocity (e.g. In

m/s). Flow Computer Device used to “pre-process” field signals and apply calculations

Fluid A substance that is capable of flowing, including all gases and liquids. Forward Processing Pumping the fluid from the inlet to the outlet of the pipeline. Such flow is counted as

positive. See also reverse processing.Gaussian Distributi on Well-known form of probability density function, published by Gauss. Many different

procedures in nature are described by this function (approximately). Gradient-Intersection-

Method

Method for leak location, where leak location specific change in pressure profile along thepipeline is analysed. PipePatrol E-RTTM uses a model based version, which is able tolocate a leak even under transient condition.

Head Statio ns

Monitoring

This Configuration of PipePatrol E-RTTM uses measurements from the Head Stations of

a pipeline to calculate the flow-residuals and monitor the pipeline for leaks. RelatedSubstations Monitoring.

Head Stations Metering Station at Inlet or Outlet Hypothesis Test Method of the statistical decision theory

Inlet The "left handed" beginning of a Pipeline, where the Fluid enters the pipeline in forwardoperation. Related Outlet.

Inventory Also: line-packing. KROHNE Oil & Gas Netherlands subsidiary of KROHNE Messtechnik Duisburg gmbh & Co. KG. PipePatrol is

the LSS-Family of KROHNE Oil & Gas. LDS Leak Detection System. A System to detect leaks in pipelines, additional leak location can

be detected, too. In Germany LDS have to make grade to the TRFL. Leak Alarm Declaration of a leak event. Related to E-RTTM-Technology this alarm will raise in case of

a spontaneous leak. Leak Flow Lost fluid at leak location in units per time, e.g. M/s, t/h or m 3/h. Leak Rate Quantitative value about the size of the leak. Absolute e.g. In m/s, t/h or m3/h. Relative in

% related to a reference value. Leak Signature Analysis Method to avoid False Alarms related to E-RTTM-Technology. Residuals are analysed for

different Leak signatures. I case of a leak Leak Alarm or Sensor Alarm will raise.

Fundamentals of Leak Detection 43



Definitions


Leak Signature Specific signature in signals, which occurs in case of a leak.

Likelihood-Ratio-Test Statistical method, to decide for one of two predefined Hypotheses (e.g. Leak no/yes) by a

collection of measured values.

Line-Packing International common definition for the change of inventory stored in a pipeline.

Local Profiles Flow- and thermodynamic Values as e.g. Pressure and temperature, described along thepipeline.

Mass Balance Method Also Balancing Methods. LDS-method, which uses the conservation of mass for leakdetection. These are compensated and uncompensated Mass Balance as well (e.g.PipePatrol SMB), In the broader sense also RTTM- and E-RTTM-Systems as PipePatrolE-RTTM

Measured Section Section of a Pipeline terminated by Metering Equipment. Is (maybe the only) part of aMeasured Section.

Measurement Statio n A station at one specific point of the pipeline, equipped with metering sensors and/or clusters. At In- and Outlet these are called Head Stations, otherwise Substations.

Monitored Section Part of a pipeline, monitored by a LDS. Consists of one ore more Monitoring Sections.

Multi-Batch-Condition Condition, where several different Batches are pumped through a pipeline. RelatedSingle-Batch-Condition.

Negative Pressu re Drop LDS method, where with Speed of sound propagating, negative pressure wave isanalysed. If several pressure meters are used, leak location can be determined by Wavepropagation method. Detects only spontaneous Leaks

Nominal Flow Flow at nominal conditions, e.g. In m3/h.

Nominal Flow Flow, given at nominal conditions, e.g. In m3/h.

Outlet The "right handed" end of a Pipeline, where the Fluid leaves the pipeline in forwardoperation. Related Inlet.

Pig System which is inserted into a pipeline on demand e.g. Separate of batches (Batch

Separation Pig).

Pipeline-Observer SW-Module, which calculates Residuals based on measured values. Is used to eliminateCompressibility and Elasticity-Effects.

Pipelin Serve the purpose to transport Fluids.

PipePatrol E-RTTM PipePatrol Extended Real-Time Transient Model; LDS by KROHNE Oil & Gas based onE-RTTM-Technology and Leak Signature Analysis. Provides Leak detection and locationin Pumping Conditions (PipePatrol E-RTTM/PC) and Shut-in Condition (PipePatrol E-RTTM/SC) for stationary state and transient state defined in API 1130 and TRFL

PipePatrol SMB PipePatrol Statistical Mass Balance; LDS by KROHNE Oil & Gas, based on the massbalance method and Leak-Classification. Provides continuous leak detection in PumpingConditions for stationary state and limited transient state as defined in API 1130 andTRFL.

PipePatrol Family of LDS by KROHNE Oil & Gas

Pressure Monitoring Simple LDS, where pressure is measured at one single location at the pipeline; Pressuredrops in case of a leak. Method is out of date.

Probability Density

Function

Function of probability theory, which enables calculation of probability for an event.Related Gaussian Distribution.

Process-Conditions Actual conditions for pressure and temperature. Also values for density and (Process-Density) and flow (Process-Flow) belong to process conditions. These values differ fromthe values at Reference Conditions in general.

Process-Density Density of the fluid at Process-Conditions.

Process-Flow Flow of the fluid at Process-Conditions.

P-T-Method Pressure-Temperature-Method. In this method pressure within a tightly closed pipeline isanalysed. The temperature is analysed too by use of the thermodynamic equation law of teh fluid. PipePatrol E-RTTM/SC uses a model based version of this method.



Definitions

Pumping Condition Condition where fluid is pumped through the pipeline. TRFL assumes special LDS for thiscondition

Reference-Conditions Defined condition for pressure (e.g.. 1,01325 bar) and temperature (e.g. 15°C Also valuesfor density and (Process-Density) and flow (Process-Flow) belong to process conditions.

These values differ from the values at Process-Conditions in general.

Reference-Density Density of the fluid at Reference-Conditions

Reference-Flow Flow of the fluid at Reference-Conditions

Reliability Criteria by API 1155, e.g. Probability for a false alarm, most times related to one year.

Residual Difference in measured values (e.g. Pressure or flow) of by Pipeline-Observer calculatedvalues assuming a leak free pipeline. Input for Leak Signature Analysis.

Residual-Method A RTTM-based Method for leak detection, where redundant measurement values areanalysed. The measured values are compared to the calculated ones; their difference iscalled Residual.

Reverse Processing Processing, where the Fluid is pumped from Out- to Inlet. Per definition flow will becounted as negative in this case. Related Forward Processing.

Robustness Criteria by API 1155; Defines the processing of a LDS, if conditions are not ideal, e.g. Thedamage of a sensor

RTTM-System Real Time Transient Model System, International common for a real-time capable modelbased LDS. The mathematical model of the flow within the pipeline is simulated onindustry computers in real-time. It is capable to handle even transient conditions.

Section Monitoring In this configuration of PipePatrol E-RTTM leak detection based on flow residual isprocessed for single Sections. Related Substation Monitoring.

Section Synonym: monitoring section

Section-Residual The Flow Residual calculated by Section Monitoring of one monitored Section.

Sensitivity Criteria by API 1155; combined criteria, combines smallest detectable leak rate as well as

time to detect a leak. Example: Lost Volume by leak rate from beginning till Leak Alarm.

Sensor Alarm Declaration of a leak event. Related to E-RTTM-Technology this alarm will raise in case of a gradual leak or Sensor Drift.

Sequential Probability

Ratio Test (SPRT)

Published by Wald, a sequential version of the Likelihood-Ratio-Test. Statistical base of PipePatrol SMB.

Single-Batch-Condition Process-Condition, where only one single batch is pumped through a pipeline. RelatedMulti-Batch-Condition.

Speed of Sound Propagation Speed of Pressure-, Density- and flow dynamics in Fluids. Leak Location byWave Propagation method is based on the speed of sound.

Spontaneous Leak A fast developing, step-like leak.

Shut-in Condition Condition, where pumps are switched off. TRFL assumes special LDS for this condition.

Shut-in Conditions Condition, where no fluid is pumped through the pipeline. TRFL makes demand for a LDScapable of monitoring shut-in conditions.

Stationary In statistical manner the time independence of the probability density function, e.g.Gaussian Distribution.

Statistical LDS LDS equipped with special statistical data processing e.g. Hypotheses Test (Leak no/yes)as SPRT.

Steady State Process Conditions for a pipeline, where physical values (e.g. Pressure) do NOT changeover time. TRFL makes demand for LDS, which are capable to monitor pipelines for leaksunder steady state conditions. Related transient condition.

Substation Monitoring This Configuration of PipePatrol E-RTTM uses measurements from the Substations of apipeline to calculate the flow-residuals and monitor the pipeline for leaks. SubstationMonitoring is proceeded additional to Head Station Monitoring. Related SectionMonitoring.

Substations. All Measurement Stations except the In- and Outlet ones




Definitions

Fundamentals of Leak Detection

Thermodynamic

Equation Law

Relation between Pressure, temperature and density (or a spec. Volume), which is truefor a Fluid

Transient Condition Process Conditions for a pipeline, where physical values (e.g. Pressure) do change over time. TRFL makes demand for LDS, which are capable to monitor pipelines for leaks

under steady state conditions. Related steady state

TRFL TRFL stands for “Technische Regel für Rohrfernleitungen”. Published in 2003 in Germanyit is applied to all Pipelines, which transport flammable and/or dangerous liquids or gases.Chapter 11.5 of the TRFL instructs LDS are necessary for a pipeline.

Volume Correction

Coefficient

Coefficient describing the relation between Process-Density to pressure and temperature.

Volumetric Flow

Measurement

Measurement, where Flow is measured as volume flow or flow rate. To determine massflow the density of the fluids needs to be known.

Wave Propagation

Method

Method to locate a leak, where the difference in runtime of a wave-like propagatingpressure drop is analysed at different locations along the pipeline. PipePatrol E-RTTMuses a model based version, which is able to locate a leak even under transient condition.

Way through Missing alarm in case of a leak

Zero False-Alarm

Methodology

Synonym: e-rttm-technology.

46



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