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  • 1. ~ ~ A P I PUBL*LL30 9 5 0732290 0547764 878 m Computational Pipeline Monitoring API 1130 FIRST EDITION, OCTOBER 1995 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 2. Computational Pipeline Monitoring Manufacturing, Distribution and Marketing Department API 1130 FIRST EDITION, OCTOBER 1995 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 3. A P I PUBL*IJII~O 95 m 0732290 O549766 640 m SPECIAL NOTES l . API PUBLICATIONS NECESSARILY ADDRESS PROBLEMS OF A GENERAL NATURE. WITH RESPECT TO PARTICULAR CIRCUMSTANCES, LOCAL, STATE, AND FEDERAL LAWS AND REGULATIONS SHOULD BE REVIEWED. 2. API IS NOT UNDERTAKING TO MEET THE DUTIES EMPLOYERS, MANU- OF FACTURERS, OR SUPPLIERS TO WARN AND PROPERLY TRAIN AND EQUIP THEIR EMPLOYEES, AND OTHERS EXPOSED, CONCERNING HEALTH AND SAFETY RISKS AND PRECAUTIONS, NOR UNDERTAKING THEIR OBLIGATIONS UNDER LOCAL, STATE, OR FEDERAL LAWS. 3. INFORMATION CONCERNING SAFETY AND HEALTH RISKS AND PROPER PRECAUTIONS WITH RESPECT TO PARTICULAR MATERIALS AND CONDI- TIONS SHOULD BE OBTAINED FROM THE EMPLOYER, THE MANUFACTURER OR SUPPLIEROF THAT MATERIAL, OR THE MATERIAL SAFETY DATA SHEET. 4. NOTHING CONTAINED IN ANY API PUBLICATION IS TO BE CONSTRUED AS GRANTING ANY RIGHT, BY IMPLICATION OR OTHERWISE, FOR THE MANU- FACTURE, SALE, OR USE OF ANY METHOD, APPARATUS, OR PRODUCT COV- ERED BY LETTERS PATENT. NEITHER SHOULD ANYTHING CONTAINED IN THE PUBLICATION BE CONSTRUED AS INSURING ANYONE AGAINST LIABIL- ITY FOR INFRINGEMENT LETTERS PATENT. OF 5. GENERALLY,APISTANDARDSAREREVIEWED AND REVISED, REAF- FIRMED, OR WITHDRAWN AT LEAST EVERY FIVE YEARS. SOMETIMES A ONE- TIME EXTENSION OF UP TO TWO YEARS WILL BE ADDED TO THIS REVIEW CYCLE. THIS PUBLICATION WILL NO LONGER L EFFECT FIVE YEARS AF- BE N TER ITS PUBLICATION DATE AS AN OPERATIVE API STANDARD OR, WHERE AN EXTENSION HAS BEEN GRANTED, UPON REPUBLICATION. STATUS OF THE PUBLICATION CAN BE ASCERTAINED FROM THE API AUTHORING DEPART- MENT [TELEPHONE (202) 682-8000]. A CATALOG OF API PUBLICATIONS AND MATERIALS IS PUBLISHED ANNUALLY AND UPDATED QUARTERLY BY API, 1220 L STREET, N.W., WASHINGTON, D.C.20005. All rights reserved.No part of this work may be reproduced, storedin a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording,or other- wise, without prior written permission from the publisher. Contact Publications API Manager, 1220 L Street, N.W., Washington, DC 20005. Copyright O 1995 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 4. FOREWORD AFI publications may be used by anyone desiring to so. Every effort has been made do by the institute to assure the accuracy and reliability of the data containedthem; how- in ever, the institute makes representation, warranty,or guarantee in connection with this no publication an hereby expresslydisclaims any liability or responsibility for loss or dam- age resulting from its use for the violationof any federal,state, or municipal regulation or with which this publication mayconflict. Suggested revisions are invited and should be submitted to director of the Manu- the facturing, Distribution and Marketing Department, American Petroleum Institute, L 1220 Street, N.W., Washington, D.C. 20005. iiiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 5. API PUBL*:1130 95 D 073229005497b8 413 W CONTENTS Page O INTRODUCTION .................................................................................................... 1 1 SCOPE ..................................................................................................................... 1 1.1 Purpose ............................................................................................................ 1 1.2 Contents ........................................................................................................... 1 1.3 Limitation Scope ............................................................................................. 1 2 REFERENCES ........................................................................................................ 2 2.1 References CitedHerein .................................................................................. 2 2.2OtherApplicablePublications ......................................................................... 2 3 DEFINITIONS ........................................................................................................ 2 4 TECHNICAL OVERVIEW .................................................................................... 3 4.1 Methodologies ................................................................................................. 3 4.2 Selection Criteria ............................................................................................. 4 4.3 Commodity Properties ..................................................................................... 5 4.4 Transportation Systems ................................................................................... 5 5 TECHNICAL DETAILS ......................................................................................... 5 5.1 Field Instrumentation ...................................................................................... 5 5.2 SCADAKommunications ............................................................................... 6 5.3 DataPresentation ............................................................................................. 8 6 OPERATION,MAINTENANCE,ANDTESTING ............................................... 9 6.1 CPM Operations .............................................................................................. 9 6.2 System Testing ................................................................................................ 10 6.3 SystemMaintenance ........................................................................................ 11 6.4 DataRetention ................................................................................................. 11 6.5 PipelineControllerTraining ............................................................................ 12 6.6 CPM Documentation .................................................................................... 13 APPENDIX A-GLOSSARY ..................................................................................... 15 APPENDIX B-DISCUSSION OF PIPELINE RUPTURE DEFINITION ............... 17 Figures 1-Representation of a LeaklRupture ...................................................................... 2 B-1-Definition of a Leamupture ......................................................................... 17 VCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 6. Computational Pipeline Monitoring O Introduction erator in the selection, implementation, testing, and opera- tion of a CPMsystem. When used in conjunction with other Computational Pipeline Monitoring (CPM) a new term is API publications, this publication will prove useful iden- to that has been developed to refer to algorithmic monitoring tify the complexities, limitations and other implications of tools that are used to enhance the abilities of a Pipeline Con- detecting anomalies on liquid pipelines using CPM systems. troller to recognize anomalies which may be indicative of a commodity release. In the past, systems have been gen- these 1.2 CONTENTS erally called leak detection systems. However leak detection can be accomplished by a variety of techniques such as: This publication includes definitions, source and reference aeriavground line patrol; third party reports; inspections by documents, concepts ofdata acquisition, discussion of de- company s W , sensors; SCADA monitoring of line conditions sign and operation of a pipeline as related to CPM, fieldin- by Pipeline Controllers; and software based monitoring. Con- strumentationfor CPM purposes, alarm credibility,Pipeline sequently the term CPM was developed to specifically cover Controller response, incident analysis, record retention, leak detection, using algorithmic tools. maintenance, system testing, training, considerations for set- The API Computational Pipeline Monitoring Task Force ting alarm limits, trending and recommendations for data (CPM-TF) was formed in April 1994. The purpose of the presentation. The relationship between the Pipeline Con- group was to develop an API publication for CPM as used in troller and the CPM systemis also discussed. the pipeline industry. The existence of thisforce was en- task tered into the Department of Transportation-Office of 1.3 SCOPE LIMITATIONS Pipeline Safety’s public docket. This publication is intended apply to single phase, liquid to This actionto address the needs of industry and regulators pipelines. It is recognized that one particular methodology or in the subject of software methods of detecting pipeline leakstechnology may not be applicable to all pipelines; each is a further demonstration of the API’s commitment to be pipeline system is unique in design and operation. In addition, proactive in helping pipeline industry to protect the pub- the detection of releasesby these means is technically complex lic and our environment. Thispublication and the working with detectable limits diffkult to quantify, so limits must be Task Force was suggestedas a logical extension of a5 year determined and validated on a system-by-system basis. API research project on leakdetection. This publicationis not all inclusive. The reader must have Recognizing that the document produced will need an intimate knowledge of pipeline and may have to refer the changes in the future, not only because of developing tech- to other publications for background information. nology but also because of regulatory requirements, the work The user of this publication mustbe familiar with the re- of the CPM-TF has been fully documented. Documentation, quirements of local be jurisdiction regulations that must con- available from the API, will provide an understanding of the sidered in theapplication of CPM to pipelines. basis for the approach for future modifiersthis publication. of CPM is intended as another toolto be used in pipeline op- eration. Pipeline Controllers must familiar with the pipeline be 1 Scope to effectively operate CPM systems. Operational usage and application of CPM systems require human judgment and in- 1.1 PURPOSE tervention. An example of this type of action would be activa- This publication focuses on the design, implementation, tion of Emergency Flow Restricting Devices (EFRDs). testing and operation of Computational Pipeline Monitoring This publication complements but does not replace other (CPM) systems which use an algorithmicapproach to detect procedures for monitoring the integrity of the line. For exam- anomalies in pipeline operatingparameters. The primary ple: trained Pipeline Controllers analyzing SCADA-presented purpose of these systems is to provide tools that assist operating data can be effective at detecting many commodity Pipeline Controllersin detecting commodity releases that are releases. Also, third party reports; pipeline patrols; employee within the sensitivity of the algorithm.is intended that the It on-site examinations are other effective procedures used to CPM system would provide an alarm and display other re- verify integrity of pipeline. This publication is in keeping the lated data to the Pipeline Controllersto aid in decision-mak- with standard industry practice and commonly used technol- ing. The Pipeline Controllers would undertake an immediate ogy; however, it is not intended to exclude other effective investigation,confirm the reason the alarm andinitiate a for commodity release detection methods. response to the anomaly when it represents an operational CPM systems, as well as other commodity release detec- upset or commodity release. tion techniques, each have a detection threshold below The purpose of publication is to assist the pipeline op- which commodity release detection cannot expected. This this be 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services ~ ~~
  • 7. ~~ A P I PUBL*1130 95 m 0732290 0549770 O71 m 2 API 1130 publication will not reduce the threshold at which a com- Manual of Petroleum Measurement Standards (instru- be modity release can detected. ments and trends) Figure 1 (along with the discussionin Appendix B) indi- CSAI cates thatC€” is only addressing commodity releases above CANJCSA-Z 183-M90, Pipeline Systems -A National Oil some practical detection limit. Standard of Canada, Appendix H,“Rec- ommended Practice forLeak Detection” 2 References DOT2 2.1 REFERENCESCITEDHEREIN 49 Code of Federal RegulationsPart 1 95 The following standards, codes, and specifications are ISA~ cited herein: “A Fog Index for CRT Displays,” by Richard S . Shirley, API Proceedings of the ISA 1985 Conference FW 1149 Pipeline Variable Uncertainties and Their Eflects on Leak Detectability 3 Definitions RP 1155 Evaluation Methodology for Sofìare For the purposes this standard, the following definitions of Based Leak Detection Systems apply. Other particular definitions words or phrases used or F P 1119 Training and Qualification of Liquid in CPM are included in the glossary. Pipeline Operators 2.2 OTHERAPPLICABLEREFERENCES ‘Canadian Standards Association, 78 Rexdale Boulevard, Rexdale, Ontario M9W 1R3. API *Department of Transportation. from Available US.Government Printing Office, Washington, D.C. 20402. l1 Doeroping a Pipe1inesupentisO~ P.O. Box 12277, Research Park, 3Instrument Society of America, Triangle Center Carolina North 27709. Catastrophic ?, Rupture CPM-detectable threshold ’ commodityrelease I ! i Practical detection Y ! limit for given pipeline I- J P conditions (use API 1155 methods) j ! Theoretical detection limit as defined by . Non-detectableleak API 1149 Seepage Figure 1-Representation of a LeaWRuptureCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services ~
  • 8. A P I P U B L * I J L ~ O 75 W 0732270 0 5 4 9 7 7 3 T O B m MONITORING PIPELINE COMPUTATIONAL 3 3.1 computational pipeline monitoring or CPM: an al- Types ofexternally based systemsor devices that will not gorithmic monitoring tool that allows the Pipeline Controller be discussed are: to respond to a pipeline operating anomaly which may be in- Fiber optic cable. 9 dicative of a commodity release. Vapor sensing tube. 3.2 commodity release: a loss of fluid from the pipeline. Dielectric cable. Within the context of this publication, a commodity release, Acousticemissions. when referencedto leak rate, must be above practical de- the Gassensors. 9 tection limit of theparticular CPM system and pipeline. An- Each of the CPM methods has its strengths and limita- other industry termis product release. tions. No one technology suitable for all pipeline applica- is tions. 3.3 pipeline rupture: in the context of Computational Pipeline Monitoring (CPM), arupture is a type ofpipeline 4.1.2InternallyBasedSystems leak that is characterized by registering a great differential Internally based systems which use CPM techniques uti- (larger than system “noise” at the time of occurrence) in lize field sensors to monitor internal pipeline parameter(s) some measuredtrended values on SCADA system. It is the such as: pressure, temperature, viscosity, density, flowrate, a commodityrelease caused by some significant mechanical product sonic velocity, product interface, etc. which are in- damage to the pipeline system that createsthis large hy- puts for inferring a commodity release by manual or elec- draulic transient inthe pipeline. The commodity release then tronic computation. causes an impairment to the operation of the pipeline. A The types of CPM internally based methodologies that pipeline rupture can be defined in part by referring to other will be discussed are: definitions. A more detailed definition and explanation is Linebalance. 9 B provided in Appendix of thispublication. Volume balance. 9 3.4 transient operating conditions: when any pipeline Modified volume balance. operating parameter is changing with respect time. to Real time transient model. Pressure/flowmonitoring. 3.5 steady state conditions: when no pipeline operating Acousticlnegativepressure wave. 9 parameter is changing with respect time. to Statistical analysis. The following is a brief description of each internally based 4 Technical Overview methodology: METHODOLOGIES 4.1 4.1.2.1 LineBalance(LB) The field and control center hardware and software will be This meter-based method determines the measurement im- this covered by publication. Sensor must be sent from field data balance between the incoming (receipt) and outgoing (deliv- sites via telemetry to a control center for data presentation, ery) volumes. The imbalancecompared against a predefined is computation, evaluation and appropriate action Pipeline by the alarm threshold for a select time interval (time window). Controller. The degree of complexity in processing field data There isno compensationfor the change in pipeline inventory varies from simple comparisons of a particular parameter rel- due to pressure, temperatureor composition. Imbalance calcu- ative to a threshold limit more extensive analysis of multiple to lations are typically performed from the receipt and delivery parameters with interlocking and/or dynamic threshold limits. be deter- meters, but less timely and less accurate volumes can All CF” algorithms are based on certain assumptions which mined from tank gauging. Line balancing can be accom- need to be completely metto ensure accuracy. Methods used plished manually because of simplicity. its to detect commodity releases can beclassified as externally or internally based. 4.1.2.2Volume Balance (VB) This method is an enhanced line balance technique with 4.1.1 ExternallyBasedSystems limited compensation for changes in pipeline inventory due This publication does not include externally based sys- to temperature and/or pressure. Pipeline inventory correction tems which operate on the non-algorithmic principle of is accomplished by takinginto account the volume increase physical detection of an escaping commodity. In these sys- or decrease in the pipeline inventory due tochanges in the tems, the localdetector sends an alarm signal the control to system’s pressure and/or temperature. is difficult to manu- It center for display and annunciation. Since the externally ally compensate changes in pipeline inventory because of for based methods do not meet the requirement of performing the complexity of the imbalance computation. There usu- is computation on field parameters for inferring a commodity ally no correction the varying inventory density. A repre- for release, they are excluded. sentative bulk modulus used for line pack calculation. isCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 9. ~ A P I P U B L * L L 3 0 95 0732290 0549772 944 4 API 1130 4.1.2.3 Modified Volume Balance (MVB) modity breachesthe pipe wall. The leak produces a sudden drop inpressure in the pipe at the leak site which generates This meter-based method is an enhanced volume balance two negative pressure or rarefaction waves, travelling up- technique. Line pack correction is accomplished by taking stream and downstream. High response rate/moderate accu- into account the volume change in the pipeline inventory uti- racy pressure transmitters at select locations on the pipeline lizing a dynamic bulk modulus. This modulus is derived continuously measure the fluctuation of the line pressure. A from the bulk moduli the various commodities a func- of as rapid pressure drop and recovery will reported to the be cen- tion of their percentage ofline fill volume. tral facility. At the central facility, the data from all moni- 4.1.2.4 Real Time Transient Model (RlTM) tored sites will be used to determine whether to initiate a CPM alarm. The real time transient model approach is perhaps the most sophisticated CPM method. The fundamental improve- 4.1.2.7 Statistical Analysis ment which RTTM provides over MVB method is that the it models allthe fluid dynamic characteristics(flow, pressure, The degree of statistical involvement varies widely with temperature). Extensive configuration of physical pipeline the different methods in this classification. In a simple ap- parameters (length, diameter, thickness, pipe composition, proach, statistical limits may be applied single parameter to a route topology, internal roughness, pumps, valves, equip- to indicate an operating anomaly. Conversely, a more sophis- ment location, etc.) and commodity characteristics(accurate ticated statistical approach may correlate the averaging of bulk modulus value, viscosity, etc.) are required to design a one or more parameters over short and long time intervals in pipeline specific RTTM. The application software generates order to identify an anomaly. a real time transient hydraulic model by this configuration The statistical process control (SPC) approach includes with field inputs from meters, pressures, temperatures,den- statistical analysis on pressure or flow or both. SPC tech- sities at strategic receipt and delivery locations, referred to as niques can be applied to generate sensitive CPM alarm software boundary conditions. Fluid dynamiccharacteristic thresholds from empirical data for a select time window. A values are modelled throughout the pipeline, even during particular method of statisticalprocess control may use line system transients. The RTTM software compares the mea- balance “over/short” data from normal operations to estab- sured data for a segment ofpipeline with its corresponding lish upper and lower volume imbalance limits. Ifvolume the modelled conditions. imbalance for the evaluated time window violates statis- the tical process control tests, the CPM system willalarm. 4.1.2.5 Pressure/Flow Monitoring 4.2SELECTION CRITERIA Three approaches to using pressure or flow information can be used. Pressure/flow values which exceed a predeter- Each CPM methodologycontains different combinations mined alarm threshold are classified as excursion alarms. of features with varying degrees sophistication.CPM per- of Initially, excursion thresholds set out of range of sys- are the formance iscontingent on the interrelationshipof many fac- tem operating fluctuations. After the system has reached a tors, for example, measurement capabilities, communications steady-state condition, may be appropriate set thresholds it to reliability, pipeline operating condition, product type, Un- etc. close to operating values for early anomaly recognition. der appropriate circumstances, rupture detection may benefit Pressurehlow trending is the representation of current and by employing multiple CPM techniques such as a volume recent historical pressure or flow rate or both. These trends balance system inconcert with pressure trending for valida- may be represented in a tabular or graphical format on the con- tion or redundancy. The independence of parameters (flow, trol center monitorto enable a Controller to be cognizant of pressure, etc.) used in some methodologies potentially allows these parameter fluctuations. This method canbe used to dis- for independent validation redundancy. The following a or is play operating changes which can infer commodity releases. list of desirable CPM features and functionality. These listed Rate-of-change (Roc) calculates the variation in a process items are not in any particular order nor is there any attempt variable with respect to a defined timeinterval. The rate at to weight the importance ofeach. It should be noted no that which line pressure or flow or both changes with respectto one methodology possesses allfeatures or functionality and time are the two most common forms ROC for pipeline of be certain features will more appropriatefor specific pipeline operation. The intent of this approach is to identify rates of systems: change inpressure or flow or both aside from normal oper- Possesses accurate commodity release alarming. ating conditions, thereby inferring a’commodity release if Possesses high sensitivity to commodity release. operating anomalies cannotbe explained. Allows for timely detection of commodity release. Offers efficient field and control center support. 4.1.2.6 AcousticMegativePressureWave Requires minimum software configuration and tuning. The acoustidnegative pressure wave techniquetakes ad- Requires minimum impact from communication outages. vantage of the rarefaction waves produced when the com- Accommodates complexoperating conditions.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services -~ ~~
  • 10. API PUBL*ll30 95 m 07322900549773 BAO m COMPUTATIONAL PIPELINEMONIT~RING 5 Is available during transients. strumentation (quality, accuracy,location), etc. These same Is configurableto complex pipeline network. pipeline systems canalso be categorized by operational fac- Performs an imbalance calculation on meters at one in- tors suchas: flow rate, magnitude and frequencyratdpres- of stant in time. surefluctuations,blending,batching, batch stripping Possesses dynamic alarm thresholds. schemes, product type, viscosity, density, sonic velocity, bulk Possesses dynamic liquid pack constant. modulus, vapor pressure, pressure, temperature, heat transfer Accommodates commodity blending. etc. Current CPM technologiescannot properlycharacterize Accounts for heat transfer. periodic or permanent slack line conditions. Provides the pipeline system’s real time pressure profile from a hydraulic model. Accommodates slack line conditions. 5 Technical Details Accommodates all types of liquids. 5.1 FIELD INSTRUMENTATION Identifies leak location with appropriate mile post locations. Identifies leak rate. This portion of the publication defines good operating Accommodates commodity measurement and inventory practice in the design and maintenance ofthe field instru- compensation for various corrections (temperature, pressure, mentation necessary to adequately support a CPM system. density, meter factor). API Publication 1149, Pipeline Variable Uncertainties Accounts for effects of drag reducing additive. and Their Effects on Leak Detectability, documents the im- API Publication 1155 can be consulted additional details for portance of instrumentation to CPM performance. This on CPM performance criteria. methodology can demonstrate that inadequateinstrumenta- tion reduces CPM effectiveness, and may also be used tode- 4.3 COMMODITYPROPERTIES termine wherethe most cost effective improvements canbe made. Suchanalysis may be used repeatedly over life of the The fluidto be monitored must in fully liquid phase in be the pipeline system to achieveincrementalperformance im- characterized. This charac- order for it to be mathematically provernent on a basis. terization is typical of most crude and refined products. oils Note that different CPM methodologies require varying For Newtonian fluids, simpler CPM packages may character- levels and types of instrumentation. Instrumentation costs ize the fluid withbulk modulus which is independent of vis- a may vary significantly for each method. Some methodolo- cosity. Other commodities such high parafh crude oilsare as gies may have veryspecialized instrumentationneeds. highly viscous and may have non-Newtonian fluid character- istics. However, these fluids can mathematically repre- be 5.1.1 Selection of Instrumentation sented with sophisticated equations when being appiied-to a Ranges andspecificationsshould becarefully matched to Real Time Transient Model (RTTn). Highly volatile liquids pipeline operating design, pressure, flow, temperature, den- (HVLs) are in liquid phase if temperature and pressure are sity, etc. to make best useof the instrument manufacturer’s sufficient to maintain the fluid above the critical point. Highly stated accuracy and linearity. Since instrument accuracy is volatile liquids are more compressible than crude oils, generally stated in terms of percent of full range,smallest the thereby making it more difficult to discern anomalies from available range greater than desired range is the preferred the normal pipelineoperations. choice. Thereis no value in over specificationof instrumen- tation accuracy if system accuracy is limited by the analog 4.4 TRANSPORTATIONSYSTEMS resolution or vice versa of SCADA system. Such limita- the This publication is written for liquid onshore or offshore tions are generally imposed by the resolution, measured in trunkline systems but much this content may be applicable of bits, of the analog-to-digital ( M D ) conversion hardware. to other piping systems such as: select gathering systems, production flow lines, marine vessel loading or unloading, AiD Bits Resolution Percent tank terminaling operations, CPM has typically been ap- etc. 8 0.4 plied to steel pipeline systems butmaybe applied to pipelines constructed of other materials such as PVC, 10 o. 1 0.025 12 polyethylene, fiberglass, concrete. The successful applica- 0.0015 16 tion of CPM may belimited by the characteristics of these other materials. 5.1.2 Installation o Instrumentation f Pipeline systems vary widely intheir physical character- istics of diameter, length, pipe wall thickness, internal Instrumentsshould be installed in accordance with manu- roughness coefficient, pipe composition, complexity of pipe facturer’s recommendations and applicable industry codes network, pipeline topology, pump stationconfiguration,in- and standards.The locationof instrumentationin relation toCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 11. ~ ~~ A P I PUBLX1130 95 m 0732290 0549774 717 m 6 API 1130 is the process equipment important, and should carefully be designed to minimize resonance. Electrical noise in sensor designed with due consideration to variations in operating wiring can oftenbe reduced through useof shielded signal conditions. cables and proper grounding. The design of the instrumentation process piping should in- When attempts to eliminate noise are unsuccessful, signal clude provision for convenient testing and calibration of the conditioning techniques may be usedto limit bandwidth and instrument with minimum disruption pipeline operations. of thus attenuate noise. For example,I 1149 describes a dig- AP ( S e e API Manual o Petroleum Measurement Standards f for ital low pass filter which was effective in reducing noise and instrumentation.) thus improving the leak sensitivity under test conditions. Note that excessive signal conditioning may remove de- 5.1.3 Calibration and Maintenance of sired information. Signal conditioning techniques intro- also CPM Instrumentation duce time lags in changing data which may reduce the A CPM performance system that has adequate instrumenta- effectiveness of the CPM system. tion to achieve the desired commodity release sensitivity may be limited in its effectiveness by instnunent calibration drift. A 5.2 SCADA/COMMUNICATIONS system that receives inaccurate data will yield inaccurate re- TheSupervisoryControl And DataAcquisition,or sults. SCADA, systemis typically a computer-based communica- Instruments should calibrated in accordance with man- tions system that gathers, processes and displays data from be be ufacturer’s reclommendations and should traceable to Na- field instrumentation.This section focuses on the design of tional Institute for Standards and Technology. Operating the data gathering sub-system and its impact on CPM. experience will provide the basis for determining an appro- Both manual and automated CPM systems will generally priate testand recalibration interval. For example, the recal- use data gathered by the pipeline SCADA system. Manual sys- ibration interval might twice per year at an interval not be to tems permit the operator to evaluate the SCADA data and exceed seven months. The CPM system performance itself combine it with data from other sources, but are usually labor may in some casesbe the best indication of the necessity to intensive and slow except on simple systems. Automated CPM test and re-calibrate particular instrument. a systems may be interfaced with the SCADA system to receive To maximize CPM performance, each pipeline company pipeline data as it becomes available. Automatic transfer of the should preparea test and calibration plan as part of CPM a data makesit possible for the CPM system to analyze the data operating and maintenance procedure. This plan should rec- at a much faster rate. Such automation does require that all nec- of ognize the importance the CPM system to the opera- safe essary databe available from the SCADA system. tion of the pipeline and provide for the priority CPM of The following paragraphsdescribe several SCADA sys- instrument repair. Note that such a plan could result instru- in tem design factors that can impact the quality and timeliness mentation calibration practices that exceed DOT mini- may of the data required by a CPM system. mum requirements. 5.2.1CommunicationsMediaand Test and recalibration events should be documented, and Error Detection such records shall, a minimum, include the date the test at of and initials of the person performing the test. Test and recal- Any data communications medium can be used for ibration records should be retained in accordance with each SCADA. but the most common media in the liquid pipeline company’s written procedures. industry are dedicated telephone circuits and various forms When developing a maintenance history for field instru- of terrestrial and satellite-based radio systems. These media mentation, consideration should be given to recording “as vary in quality, but all are subject noise and interference to found” and “as left” calibrations. causing data corruption. Virtually all SCADA systemsare Procedures should be developed coordinate the test and designed to detect and reject corrupted messages, “Data to recalibration of field instrumentation with Pipeline Con- quality bits” are often available in the SCADA system to in- trollers and CPM system maintenance personnel, since recal- dicate lost messages, and should be used by the CPM system ibration may affect performanceof the system. to identify missingor questionable data. 5.1.4 Signal Conditioning 5.2.2 CommunicationsMessageStructure Noise is that partof the signal received that does not rep- SCADA systems gather data from field instrumentation resent the quantity being measured. Noise typically exists to via a Remote Terminal Unit (RTU) located the field site. at some degree in all measured data. Noise reduces the perfor- Data is collected in one or more computers called the Master mance of the CPM system. Terminal Unit (MTU) associated with the pipeline opera- All practical means should be employed to reduce me- tions control center. The specifications the messages be- of chanical or electrical sourcesof noise at the instrument. For tween RTU and MTU are collectively referred to as the example, instrument mounts and process piping should be communications protocol.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services ~
  • 12. COMPUTATIONAL PIPELINE MONITORING 7 The protocol is saidbe “polled” when the to MTU requests the communicationschannel. Noise inthe analog signal will data from each RTU in turn. When the last RTU has been appear to be a valid change in data in quiescent and report- polled, the MTU will return to the first, repeating the cycle by-exception systems. In such a case, analog deadband is the endlessly. The time interval required to poll all RTUs and re- increased to reduce the effect of noise and minimize un- turn to the first is referredas “polling time”or “scan time.” to wanted messages. An RTU mayfail to report when polled due equipment to When the precision of the SCADA system’s analog-to- failure or noise in the communications channel. This fault digital conversion hardware exceeds the repeatability of the condition, sometimes called “no reply”is often indicated by sensor, it is appropriate to reduce the precision through the SCADA systemquality bits. use of an analog deadband. Care must be taken not to use an If the RTU always reports all its in response a poll, data to excessively large analog deadband since this technique ef- the systemis said to be “strictly polled.” Scan time is thus a fectively reduces the precision of the analog value. constant and is determinedby the quantity of data to be re- ported by the RTUs. To gain efficiency onthe communica- 5.2.5 The Impact of SCADA System Design tions channel, some protocols permit the RTU to respond on CPM with only the data that has changedsince the previouspoll. CPM systems that rely on the SCADA System for data Such protocols are referred to as “Report by Exception.” gathering must be designed with an understanding of the un- Scan time in a Report by Exception protocol may vary de- derlying communications protocol.It is possible tohave pending on system design. variation in communications protocol within one SCADA SCADA communicationsmay also be non-polled. “Qui- system. It is not unusualto find that multiple protocols may escent” or “unsolicited” operation refers to RTUs which re- be used inlayers or sequentially to complete transmission of port without being polled, either on a time scheduled basis or one RTU to MTU message. The use of multiple protocols when field data changes. Refer to 5.2.4 for a description of may adversely affect scan time. analog data change. The design of quiescent systems may in- clude provision for the MTUto poll for all RTU data. Such 5.2.6Data Processing a poll is used to verify the validity of the data image in the Field data received by the SCADA system is generally MTU and is called an “integrity scan.” coded in the most compact manner possible to maximize ef- ficiency on the communications link. Such is said to be data 5.2.3 CommunicationsTiming “raw.” The data processing function in the SCADA system is In polled systems the variation in reporting times from one responsible for converting the data to a format suitable for RTU to another called “time skew.” Designers of CPM sys- display and use byapplications such as CPM systems. This is of tems must also consider the impact time skew in the data. section describes data processing features that enableor im- Quiescent systems that report on data change and Report prove CPM functionality. so by Exception protocols have no defined scan time the age of aparticular item ofdata may be in question. To deal with 5.2.6.1 Time Tagging thissituation,some SCADA systemsgenerate“time Time tags record when a particular point was last up- data tags,”either in the RTU at the time data changes or in the dated. Some systemsgenerate the time tags in the RTU, but MTU at the time data is received. “Time tags” may be used it is more commonfor the SCADAMTU to create the time by CPM systems designed to analyze transient conditions in tag at the timethe data is processed. Time tags canbe used the pipeline. Some SCADA systems are capable of capturing the CPM systemto reduce the effect of time skew, by espe- volumetric measurement simultaneouslyin all RTUs. This cially when accumulatorfreeze is not available. feature is usually called “accumulator freeze” and effectively permits all volume data to be polled at one reference time. 5.2.6.2 Data Quality CPM systems not equipped handle time tags to may usethis Data quality information may be stored with processed method to eliminate time skew. data. Typical data quality values are: 5.2.4 Analog Deadband “Nonupdated” causedby an RTU that is off-line or not re- sponsive. Measured variables from instrumentation are sometimes “Manual data” when manually entered data overrides called SCADA “Analogs.” Report-by-exceptionprotocols scanned values. and Quiescent systems that report changed data sometimes “Range error” when a raw analog value outside spec- falls permit “Analog Deadbands.” When the Analog Deadband is ified hardware limits. enabled, the value ofthe Analog must change more than the deadband value before the new value is reported “ T . to the Data quality values may be used by the CPM system to Analog Deadbandsare generally usedto reduce traffic on help recognize and compensate questionable data. forCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 13. A P I P U B L t L L 3 0 95 m 0732290 05Lt977b 59T a API 1130 5.2.6.3 Analog Processing Chronological alarm logs/files. Unacknowledged alarm summaries. Analog values represent measured variables suchpres- as Summaries of points in an abnormal state. sure or flow rate. Raw analog values are scaled into engi- neering units such pounds per square inch as (PSI), or barrels CPM systems may be closely integrated with the SCADA per hour (BPH),by the analog processor. The scaled analog system and make use the alarm processing system dis- of to values are usually comparedto predefined threshold values play, annunciateand log CPM alarms and events. to detect when the values fall outside the desired range. The 5.2.6.7 Archiving Data rate of change is a calculated analog value, which calcu- is lated by change in value dividedby the change in time. The SCADA system may, at specified time intervals, store CPM systems generally rely on the scaled analog values data values toa historical database. This process referred is from the SCADA system. SCADA analog processing alone to as archiving. The SCADA system or other applications can be used to implement a pressure/flow monitoringCPM such as CPM systems may access the archive for historical (see 5.1). data. The ability to replay archived SCADA data in a test mode can be useful in analysis and tuning of the CPM. 5.2.6.4 Status Processing 5.3 DATAPRESENTATION Status data records the state item of field equipment. of an Status pairs such asodoff or openedclosed can be stored in Data presentation capabilities vary widely depending on one binary digit or bit. Some SCADA systems permit the the SCADA/CPM system. The contents of this section are configuration of status in 2-bit (4 state) or 3-bit (8 state) intended to assist the pipeline company achieve the best to combinations. For example, valve status is sometimes possible results in theexisting system. represented by the four states: opened/in travelklosedfault. Effective presentation Operating and CPM will en- of data Changes in equipment state are generally logged to a able the Pipeline Controller to more easily identify and inter- printer or other permanent recording device by the status pret anomalies. processor. Such a set of records is usually referred to as an Interpretation of results from manual CPM systems are “event log.” based on Controller training. Therefore, this section ispri- CPM systems may need status information to determine if marily concerned with the presentation data from an auto- of transient conditions are the result of change in equipment mated CPM system. state. The event log aisgood sourceof information when in- terpreting CPM alarms. 5.3.1 Display Ergonomics 5.2.6:5 Accumulator Processing Displays needto be simple, easy to read, and presented in an uncomplicated screen arrangement. The CRT’s should be Accumulator values represent an accumulated total of positioned ina manner to avoid causing body and eye strain. start some process quantity since the of the totalization proc- It is important to consult the user during the design of the ess. In liquid pipeline SCADA service, accumulatorstyp- are CPM system,so that the Pipeline Controller satisfied with is ically used to record volumetric mass quantities passing or a the layout and design. The display should limit the number given point in the system. of colors (see Shirley’s Fog Index Section 2). in A line balance CPM system may be based upon simple Uppercase lettersmay be morereadable on some screens. arithmetic operations on accumulator values representing The information displayed should easy to read on the spe- be liquid volumes pumpedin and out of the pipeline system. cific display equipment that Controller is using. Screen the More complex CPM systems may also require accumulated savers should not be used. If other tasks are on the same volumetric data. CRT, care should be taken to prevent interference with the monitoring of the CPM system. 5.2.6.6 AlarmProcessing 5.3.2 Trending Alarms area special case of events which indicate tran- a sition into an unexpected abnormal state. The return tran- or Trending operating parameters (flowrate, pressure, vis- sition to the normal is generally referred to “return to state as cosity, density,ovedshort and temperature) ofthe SCADA normal.” system values may help determine what caused the alarm. Alarms can be configured to trigger an audible signal, The trend will have to cover a long enough duration to see which canbe acknowledged or silenced by the Pipeline Con- values from before the CPM alarm occurs right through the troller. The Controller may be requiredto acknowledge also time when the alarm ends, the current time. Trending ana- or each alarm as it is displayed. Many SCADA systems have log values can aid in troubleshooting of alarms because the special summary lists related to alarms: the analog device alone cannot always give all the infor- ofCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 14. COMPUTATIONAL PIPELINE MONITORING 9 mation needed to make a correct Leak Declaration. Tabular pipeline system. An alarm could be triggeredby equipment trends are not as easy to analyzeas graphical trends, butare failure, abnormal pipeline operating condition an uninten- or still effective ways to display historical data. tional commodity release. Since the potential of alarm infor- mation identifies conditions other‘than just commodity 5.3.3 AlarmDisplay releases which need attention, the company procedures CPM alarms should be consistent with SCADA system should also require that all alarms beevaluated. alarms and should have an appropriate priority. The alarm The quality of measured pipeline data and calculated data should have anaudible tone, and can be varied for different values and the analysis of this determines the credibility data categories of alarms. Alarms should have different colors if of an alarm. An alarm condition on a monitored pipeline is there are different categories of alarms. Acknowledged and not the end of theanalysis. unacknowledged alarms should be available to the Con- 6.1.1 AlarmCredibility troller without using several steps to get to the alarms. A time stamp should be of the alarm whenit is displayed. part The credibility of CPM system is determined an anal- a by Alarms should be presented as both audible and visual. ysis of the CPM alarm. In this publication, CPM alarmsare Visual alarms should be presented such a way as to persist in subdivided into three classes, which are: data failure, tran- so for some period of time, especially as not to beoverwrit- sient operatingconditions, and possible commodity release. ten irrevocably by newer alarms. Acknowledged alarms 6.1.1.1 Failure Data which are still in the alarmstate should remain readily avail- able to theController. This alarm would be used when input is missingor is data Provision should be made against an alarm being easily determined to be incorrect.A communication failure at a lo- defeated, or inhibited without just cause. The use of screen cation is a type of missing input data. example of incor- An savers or any other screen blanking is stronglydiscouraged. rect data could be a pressure instrument that consistently reports values that have no hydraulic relationto other pres- 5.3.4 Integration of CPM and SCADA sure and flow data on the pipeline. A procedural failure could be when a required report is not passed along to the The display of alarms from the CPM system and SCADA Pipeline Controller on schedule. These incidents would be system should preferably be integrated and put on the same presented as types of failure alarms. These alarms could data alarm display. If the CPM and SCADA systems cannot be be automatically generated by a computer or as manual en- integrated,the CPM alarms should be displayed so that they tries in a Pipeline Controller’sshift log. Some CPM systems will be readily noticed. In either case alarms should be would indicate the impact the data failure situation would logged andretained. have on continued CPM operation. The impact of thisclass Non-integrated systems should provide event and alarm of alarm could range from the system being disabled to a retention for the CPM. All displays and should be easily data fixed percentage error in future location calculations. At this accessible by the Controller to aidin operations of the CPM point analysis by the Pipeline Controller would be required. system along with the SCADA system. The hardware de- The main issue is thatthe failure of one or a series of meas- signed should provide sufficient resources, either by organi- ured or calculated data points should not trigger a Leak Dec- zation of displays or providing sufficient CRT’s to display laration. The CPM analysis system should identify data needed information for analyzing alarms. One useful refer- failure situations and notify the Pipeline Controller that a ence in the design of Pipeline Controller systems is Shirley’s problem exists. Fog Index. 6.1.1.2 Transient Pipeline Operating Condition This alarm would be used when a data set was outside 6 Operation, Maintenance, and Testing normal operating ranges, fails all tests for a data failure con- 6.1 OPERATIONS CPM dition and does not meet alltests for a possible commodity release. This class of alarm is intended to provide third di- a CPM systems usea set of procedures defined a given for agnostic condition between normal pipeline operation and a pipeline and instrumentdata, configuration data, product ac- correct Leak Declaration. If the data analysis section of the counting data, and/or calculated using various hydraulic data CPM system cannot determine a set level of certainty that to a algorithms to alarm a possible commodity release on given a commodity release situation does exist, then the CPM operating pipeline. system would call for an abnormal pipeline operating condi- In the context of CPM, an alarm is an automated or man- tion alarm. The purpose of this of alarm is to minimize class ual signal or other presentation of data to the Pipeline Con- incorrect Leak Declarations. The abnormal pipeline operat- troller (via a SCADA system operator interface or manual ing condition alarm would notifya Pipeline Controller of a tabulation sheets) that defines an abnormal condition on a problem that requires immediateinvestigation.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 15. 10 API 1130 The Pipeline Controller would review all current operat- achieved or maintained. This section outlines testing meth- ing data and make a decision on what action to take. The ods and intervals. procedures the Pipeline Controller would follow under this 6.2.1Testing Method situation wouldbe as defined by the individual pipeline com- pany for the particular CPM system. The abnormalpipeline CPM systems should be tested with actual or simulated operation alarm could supply to thePipeline Controller data commodity releases. Possible methods of testing include: to aid in the situation analysis. Continued refinement ofthe Removal of testquantities of commodity from the line. analysis section of the CPM system would reduce num- the Editing of CPM configuration parameters to simulate bers of this class of alarm, allowing the CPM system to prop- commodity loss (software simulations). erly classify more alarms as datafailure or possible Altering an instrumentoutput, for example a meter factor, commodity releases. The main issue is to minimize the oc- or to simulate a volume imbalance, a pressure output to sim- currence of a Leak Declaration until the data indicates with ulate a hydraulic anomaly. a high probability the presence of an actual unintentional dis- charge condition. The method used will be specific to the particular CPM application and pipeline system. 6.1.1.3PossibleCommodityRelease CPM tests may be “announced” or “unannounced.” An In the case where the CPM alarm does not meet the con- unannounced test is started without the knowledge of the dition for data failure described above and does not appear Pipeline Controller and tests the CPM systemas well as the as to be part of transient operating conditions, then a Leak Dec- response of the Pipeline Controller. Generally, unannounced laration may be made. APipeline Controller determines if a tests are preceded by successful announced tests. An an- Leak Declaration must be made, opposed to a purely au- as nounced test is started with the awareness of the Pipeline tomatic system. In this manner, company policy and applica- Controller and tests only the CPM system. ble regulations canbe properly applied. 6.2.2 Initial Tests During CPM Commissioning 6.1.2OperationalResponses to Alarms A new CPM system must be tested to verify that it has The followingitems should be considered when respond- achieved the expected performance. Throughout the startup ing to CPMalarms: procedure, there will likely be a variety of tests. Considera- tion should be given to testing by actual removal of com- CPM alarms willbe probabilistic, and should beassessed modity fromthe pipeline. in light of the current sensitivity threshold. Known cases where the Transient Pipeline Operating Con- 6.2.3 Retesting dition alarms have been generated should be well docu- CPM applications should be tested on 5-year interval to a mented to assist the Controller making informed decisions. in demonstrate their continued effectiveness. is not necessary It All occurrences of a Leak Declaration should be histori- to test each pipeline system which uses same CPM appli- the cally documentedas to cause andController response. cation, but consideration should be given to rotation of the Instances of automatic closed-loop control response to tested pipeline and the location of the test from one test to alarm conditions should be avoided, in that appropriate Con- the next. Consideration should be given to testing actual by troller response is preferable to automatic valve closures. removal of commodity from the pipeline. Automatic valve closures can potentially result excessive in Operational use of CPM system, for example successful a surge pressure in liquid pipeline systems. If automatic valve detection of a commodity release,is an acceptable substitute closures are unavoidable, then the Controller must have the for periodic retesting. capability to override the automatic system just cause. for Consideration should be made for an indication of CPM 6.2.4Record Keeping system failure, especially if automaticclosed-loopcontrol is Records detailing the initial or retest results shall be re- provided. tained until the subsequent test and should include: Possible causes should be accounted for, including com- puter failure, but also including possible types of system Date, time, and duration of the test. analysis failure. These and other CPM alarms should be pre- Method, location, and description of the commodity with- sented to the Controller in a way that clearly identifies the drawal. alarm as distinct from a SCADA alarm. Operating conditions at the time of the test. Details of any alarms generated duringthe test. 6.2SYSTEM TESTING Analysis of the performance of the CPM system and, Effective testing of automated CPM systems provides as- for tests, the effectiveness of the response by operating surance that the expected level of performance has been personnel.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 16. ~ ~~ A P I P U B L * l l 3 0 95 m 0732290 0549779 2T9 m COMPUTATIONAL PIPELINE MONITORING 11 Documentation ofcorrectivemeasures taken or mitigated tion after the change should not be immediately incorporated as a result of the test. in the on-line production system, but instead should be acces- sible and tested only in an off-line mode, if possible. 6.2.5Maintenance Testing It is desirable that the system build a “read only” data Throughout the life of the CPM system it will be neces- file which records relevant changes to software and param- sary to reconfigure and retest the software when the pipeline eters. An audit trail should be maintained to include date, system, SCADA system instrumentation changessignifi- or time, parameter, original setting, new setting and person cantly. When documented in accordance with 6.2.4, such performing the change. maintenance tests may set thestart of a new testing interval. All alarms and operator initiated commands and events which are part of data retention shouldstored in hard copy be 6.2.6 Testing Self or “read only” format. All “read only” files should be pro- Some automated CPM systems may be capable of running tected from loss and unauthorized tampering. self diagnostics on a scheduled basis. Suchdiagnostics typ- The operating company should develop and implement a ically introduce perturbations in the input data to see if the revision and release policy for software or firmware or both appropriate alarms are generated. This may be a desirable used in a CPM system, including field devices which input system feature if the disruptive effect these diagnostic of data to the CPM system. alarms on thePipeline Controllers can be minimized. 6.3.2ParameterandLimits 6.2.7 CPM Testing and Reduced Performance Consideration should be given to allow the Pipeline Con- When testing the CPM system, consideration should be troller to make changeslimits that are important to day-to-day to given to the potential forreduced level of pipeline monitor- a or shift specific operation. The system design should include ing during the test. Pipeline Controllers should be alert to the provisions to allow the Controller to modify and adjust limits possibility of an inadvertent commodity release which might within fixed boundaries. Changes that affect the long-term op- otherwise be ignored or misdiagnosed during the test interval. eration of CPM should not allowed by the Controller. be The ability to make changes in the CPM system bound- 6.3SYSTEM MAINTENANCE aries should only beaccessible to authorized personnel and r under the control of appropriate written procedures. Provisions shall be madeto minimize the effect of main- tenance on the integrity of the CPM during periods of hard- 6.3.3 System Degradation ware, software and field equipment maintenance and system The Controller must be informed or have an indication upgrades. whenever a CPM system sensoris inhibited or disabled or 6.3.1 Security both which causes the system operate in a degraded mode. to This should include sensor’s calibration problems, commu- Provisions shall bemade to limit access to making nications problems and software failures. changes to the SCADNCPM system, logic solver (that is, System maintenance should be performed under the con- PLC, RTU,etc.), alarm limits, and to deactivation of sensors. trol of a formal maintenance procedure that addresses the ef- The access protection may be in the form of passwords, fect of field and system maintenance on the CPM locked cabinets, “read only” or “write protected” data, and performance. The procedure should also address the commu- administrative procedures. Access protection have vary- may nications requirements between maintenance personnel and ing levels of accessibility for the different users, for example, the Pipeline Controller. systems designers, technicians,Pipeline Controllers. Provisions should be madeagainst any alarm, parameter, 6.4DATA RETENTION and/or sensor being inhibited without cause. just Access control and security should be provideda com- by The retention of data and reports from a CPM system bination of application logic and passwords for any CPM will be governed by several factors, including regulators’ user interface device, parameter, alarm inhibit, and/or limit requirements, legal requirements, engineering and opera- or which could interfere with degrade the performance of the tions requirements and Controller training requirements. CPM function. The data retention plan of the CPM system must first System changes canbe made in a number of ways. These identify each CPMreport and data set. After the CPM data changes should be coordinated otherwise managed, ex- or for has been identified it must be classified as to reason for re- ample by segregating the degree of changes by multiple levels tention. The data will be archivedfor regulatory, engineer- of accessibility. It is desirable that any changes be audited and ing and operations, operator training, or a combination of the changes should not go on-lineactive until validation is or reasons. Each reason for archiving may have a different re- complete. Any parameter or function which requires valida- tention requirement. The CPM data retention plan shouldCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 17. API PUBL*LL30 95 0732290 05Y9780 TL0 m 12 API 1130 take this fact into account. The plan shoulddefine the man- types of CPM-related SCADAalarms, such as “Communi- ner and location of all data which will be archived. cation Outage.” In general, regulatory and legal requirements for the re- 6.5.2.2 Instrumentation tention of data will be defined byothers. Data retained for engineering, operations and Controller training can be de- The Controller should be able to qualitatively identify the fined by the pipeline company. The pipeline company impact of an instrument failure on the potential of the CPM should prepare a schedule for the retention of appropriate system. The person should trained to link the alarm event be CPM systemreports and data sets. Retained CPMdata and with the conceptthat the CPM system would be impaired. reports, such as alarm reports, can be used by engineering 6.5.3ValidatingCPMAlarms groups to refine the operation of the CPM system. Opera- tions groups can use retained CPM data to analyze abnor- It is recommended that the Pipeline Controller be trained mal pipeline operation and refine pipeline operations. In to recognize abnormalconditions and totake appropriate ac- addition, retained data can be used to train Pipeline Con- tion. trollers in the operation of the CPM system. 6.5.4 Inventory Control 6.5.4.1 Line Pack 6.5PIPELINECONTROLLERTRAINING A fundamental component inventory control is the cal- of Appropriate Controller training is recommended for any culation of mass balance, the comparison of net-barrels-in or CPM system. CPM alarms maybe the most complex type of versus net-barrels-out. Controllers should be trained to rec- alarm experienced by the Controller and therefore specific ognize hydraulic changes due to varying line pack. This training and reference material is necessary to prepare the Con- would include the ability to recognize the packing behavior troller to adequately recognize and respondthese alarms. to of the pipeline(s) which they operate. Pipeline Controllers must be trained in the recognition of CPM alarms. This requires both a knowledgeable perspec- 6.5.4.2 SlackLine Flow tive on the alarms themselves as well as the nature of the A Controller should be knowledgeable about sections of alarms. The American Petroleum Institute has created a Rec- the pipeline that are susceptible to “slack line flow,” that is, ommended Practice for ControllerTraining whichconsiders a pipeline which is flowing with some type of liquid/gaseous many important issues outside the scopeof thispublication. interface. Refer to the P I Publication 1119 for more detailed informa- A tion regarding Controller training. 6.5.4.3 Trending The following technicalareas should be considered: A Controller should be able to recognize that trending and 6.5.1 Hydraulics analysis of certainpipeline variables providesa simple form of CPM system. Trending can be presented graphically, but 6.5.1.1Steady State is often simply a tabular display of historical data. The PipelineControllersmust be trained the basic con- in 6.5.5CPMSystemOperation cepts of pipeline steady state hydraulics. The gradual change of the line hydraulics due to movement of different fluid 6.5.5.1 Operation batches or temperature change,for example, should be part Each CPM system has unique presentation. It is impor- a of a Controller’seducation. tant that the Controller be trained to understand the CPM 6.5.1.2 Transient system and concepts its operation.A portionof Controller of training should include periodic review of the use of the Everyday pipeline transients can cause upsets in a CPM CPM system. system. The upsets may cause operating alarms which are well within the realm of normal system behavior. A Con- 6.5.5.2 Alarms troller mustbe trained to recognize the effects of pumpstart- CPM alarms should readily recognizable. Therefore the be updshutdowns, a valve operation switch, etc. Any of these Controller must be trained to interpret alarms correctly and will cause a system transient to appear will therefore po- and in a timely manner. tentially be a problem for the CPMsystem. 6.5.5.3 Presentation Data 6.5.2 Alarming The presentation of CPM alarm data is a crucial compo- 6.5.2.1 SCADA or nent, such as the trend of the probability of a leak the de- Some SCADA alarms impact CPM system performance. scription of the location which possible commodity release for The Controller should be able to recognize and react to all has occurred. A Controller must be trainedthe recognition inCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 18. COMPUTATIONAL PIPELINE MONITORING 13 of the first CPM notification and must be trained to research ees responsible for the CPM system on the pipeline. It is rec- the alarm (Possible Commodity Release Abnormal Condi- or ommended that the following information available: be tion) in order to pursue the appropriate response. System map,profile and detailed physical description for 6.5.5.4 Abnormal Functions each pipeline segment. Summary of the characteristics of each producttransported. The Controller must be trained to react to the abnormal Tabulation of the inputs used in the CPM procedure for each function of a CPM system in same way as for the abnor- the pipeline segment and a description of how thegathered. data is mal function of the SCADA system. The of either must loss List of special considerations or step-by-step procedures elicit certain predefinedactions intended to preserve system to be used in evaluating CPM results. integrity. 6.6 CPMDOCUMENTATION Each CPM system employed on a pipeline should be fully described and readily available for reference by those employ-COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 19. APPENDIX A-GLOSSARY accumulator data: A SCADA data value that representsan historical data: Data thatis retrievable in chronological or- accumulated quantity, usually volumeliquid pipeline in service. der, typically maintained a SCADA system data archival by subsystem. accumulator freeze: A feature of some SCADA protocols that allows all volumetric data to be captured simultaneously.integrity scan: A special message in a "report-by-excep- It may be used toeliminate time skew in volumetric data. tion" SCADA communication protocol that verifies that the MTU has an accurate picture of RTU data. Since only alarm: A notification to the Pipeline Controller that an changed data is reported the RTU in such protocol, lost by a anomaly hasbeen detected that is outside preset limits. The RTU to " messages could result inaccurate data in the J in event requires a response from the Pipeline Controller. Alarms are usually displayed a prominent manner with in an m. audible signal to the Pipeline Controller. This may be de- Leak Declaration: A Leak Declaration is made if the clared visuallyor audibly or both. Pipeline Controller has determined confmed that a prod- or uct release has occurred on the pipeline. For example,Leak a alarm acknowledgment: An action by the Pipeline Con- Declaration would be made aftera possible commodity re- troller, signifying that the alarm event is recognized. lease has been field verified. Leak Declaration initiatesa A analog data: A SCADA data value that represents some number of events in the operations, forexample shutting measured quantity, for example temperaturepressure. or down the line.See also possible commodity release. analog deadband: A SCADA parameter that defines the in- possible commodity release: A condition where the CPM crement of change in an analog value that significant. An is system has alarmed, and data failure or transient operating analog value change less than the deadbandbe ignored. will conditions causes have been ruled out. A possible commod- ity releasemay not be a reason to shutdown the pipeline but false alarm: A commonly misused term in the context CPM of would triggera full investigation of cause(s). A possible the systems to refer to transient alarms (see6.1.1, Alarm Credibility, commodity release in which the Pipeline Controller has a for discussion) that not causedby an actual commodity re- are high degree of confidence that it is true could be immedi- lease or other emergency or abnormal condition. ately escalated to Leak Declaration. company procedure a A excursion alarm: An alarm that indicates an anomaly has may require that all possible commodity releases classi- be occurred that is outside the defined limits; typically a fied as Leak Declarations. See also Declaration. Leak SCADA or CPM system generated event that alerts the manual system: A CPM system which is based upon non- Pipeline Controller an analog data value that has been de- software algorithmic calculations. to tected outsidea preset range. Also called threshold alarm. a material balance: A mathematical procedure based upon the communication failure: An interrupt in SCADA messag- laws of conservation of mass and fluid mechanics which is ing usually between the MTU and RTU. may be loss of It used to determine if a commodity release has developed in a communication eitherby total outageof the communication pipeline system. May also sometimes be called mass balance. link or by failure of the remote to respond to MTU def- site inition needed requests. master terminal unit or M W : A component of a SCADA system, usually located at the Control Center, that gathers and communications messaging protocol: See protocol. displays process data from RTUs. In addition, the Pipeline the data archiving: A SCADA system feature that records data Controllers operational commands are initiated theMTU on in an historical database. RTU. for transmission to the selected Also a generic term that refers to any device that issues request for information an to data quality: A SCADA system feature that creates status RTU or receives information from RTU. an bits that reflect the validity of process data. noise: An unwanted component in a process signal. Noise event log: A SCADA system feature that creates a permanent may be reduced by filtering. record of changes to the systems state in chronological order. no reply: A state in SCADA communicationsin which the filter: A device or algorithm to remove unwanted compo- RTU does not make a valid response to the MTUs request nents froma process signal. Also called signal conditioning. for process data. reply is expected some percentage the No of fluid properties:The characteristics the fluid that describe of time, depending on the design of the communication channel. its hydraulic behavior density, compressibility (or bulk mod- polling: One type of SCADA communications protocolin ulus), coefficientof expansion and thermal capacity. which sequential requests for process data from RTUsis- are 15COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 20. A P I PUBL*1130 95 m 0732290 549783 2T 0 7 m 16 API 1130 sued by the MTU. These requests, called polls, typically pro- remote terminal unit RTU: A SCADA system compo- or ceed in a continuous cyclic manner. nent, typically installed at a field site, that gathers process data from sensors for transmission to the MTU. The RTU pipeline controller: A person who is responsible for the also accepts control command messages from the MTU and monitoring and direct control of a pipeline. Thisis the new transforms those commands electrical output signals. Also to accepted industry term for this position (soutlined in API a a generic term that refersto any device that can respond to Publication 11 18).Other industry terms used are operator or requests for information from MTU or PLC or can send an dispatcher. unsolicited information in non-polled environment. a protocol: The specifications of the messages between RTU SCADA: An acronym for Supervisory Control and Data and MTU are collectively referred as the communications to Acquisition, the technology that makes it possible to re- protocol. motely monitor and control pipeline facilities. quiescent protocol: One type of SCADA communication sensitivity: A composite measure of the size of a leak that protocol is which the RTUs initiate messages containing pro- a CPM systemis capable of detecting andthe time required cess data for transmission to the MTU. Such messages can for the system to issue an alarm in the eventa thatcommod- be triggered by a change in process dataor created on a time- ity release of that size should occur. This term is fully de- driven basis. Also called unsolicited protocol. fined and discussed in API Publication 1155. report-by-exception: A feature of some SCADA commu- scan time: The time interval required to all RTUs ona poll nication protocols intended improve communicationeffi- to SCADA communication channel. Also called polling time. ciency by reporting onlythe data that has changed since the status data: A SCADA data value that represents the oper- previous poll. ational state of an item of field equipment. rate of change: A calculated value that reflects the change single phase: A fluid state, either liquidor gaseous, based upon in an analog data value per unit time. commodity, vapor pressure, pipeline pressure and temperature. return t normal: The transition from alarm to normal state slack line: The condition where a pipeline segment is not o that signifies that an alarm condition has ended. entirely filled with liquid or is partly void. May also be called column separation. reliability: A measure of the ability of a CPM system to render accurate decisions about possible existence of a the time skew: The variationin reporting times from one RTU commodity release ona pipeline, while operating within an to another in polled SCADA communications protocol. a envelope establishedby the CPM system design. This term time tag: A SCADA system feature that records the time is fully defined and discussed API Publication 1155. in that a measurement or event occurs along with data. theCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 21. APPENDIX B-DISCUSSION OF PIPELINE RUPTURE DEFINITION Pipeline ruptureis defined in this appendix the context in If a requirement existsto recognize a commodity release of how it relates to CPM. Figure B-1 provides a representa- size above which a rupture is defined, it should be done by tion of rupture as it relates to other@pesof pipeline leaks. the pipeline operator. defining a rupture onan individual In The definition of rupture in this figure also references other a pipeline, the pipeline operating companymay need to con- definitions to help the reader understand its relationshipto sider the following: various detectability thresholds. Slack line flow. A rupture in any case cannot considered tobe at a fixed be Line pressure. value of product release relative to the flow rateor vol- line Operating state. ume of the pipeline. The following factors characterizea CPM methodology. NptUre: SCADA scan time. Volume of product loss that occurs ina r u p m will be dif- Flow rate. ferent for each individual pipeline. Temperature gradient. Operating conditionsof the pipeline (steady or transient) CPM pipeline segmentation. will influence the minimum size of commodity release Pipe volume and length. above which a leak can be called a rupture. be Time interval should considered in defining pipeline a rupture. - catastrophic CPM-detectabIe commodity release Practical detection limit for given pipeline conditions (use AP1 1155 methods) Theoreticaldetection limit as defined by A I 1149 P - Nondetectable leak Seepage Figure B-i-Definition of a Leak/Rupture 17COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
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