NACE 1D199-1999 Internal Corrosion Monitoring of Subsea Production and Injection Systems《海底生产和注射系统的内部腐蚀监测 项目编号24202》.pdf

《NACE 1D199-1999 Internal Corrosion Monitoring of Subsea Production and Injection Systems《海底生产和注射系统的内部腐蚀监测 项目编号24202》.pdf》由会员分享，可在线阅读，更多相关《NACE 1D199-1999 Internal Corrosion Monitoring of Subsea Production and Injection Systems《海底生产和注射系统的内部腐蚀监测 项目编号24202》.pdf（13页珍藏版）》请在麦多课文档分享上搜索。

1、Item No. 24202NACE International Publication 1D199This Technical Committee Report has been preparedby NACE International Task Group T-1D-46* onDevelopment Strategy for Internal Erosion and CorrosionMonitoring and/or DetectionInternal Corrosion Monitoring of SubseaProduction and Injection Systems Jun

2、e 1999, NACE InternationalThis NACE International technical committee report represents a consensus of those individual members whohave reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyonefrom manufacturing, marketing, purchasing, or using product

3、s, processes, or procedures not included in this report.Nothing contained in this NACE International report is to be construed as granting any right, by implication orotherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by LettersPatent, or as indemnif

4、ying or protecting anyone against liability for infringement of Letters Patent. This reportshould in no way be interpreted as a restriction on the use of better procedures or materials not discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictable

5、circumstances maynegate the usefulness of this report in specific instances. NACE International assumes no responsibility for theinterpretation or use of this report by other parties.Users of this NACE International report are responsible for reviewing appropriate health, safety,environmental, and r

6、egulatory documents and for determining their applicability in relation to this report prior to itsuse. This NACE International report may not necessarily address all potential health and safety problems orenvironmental hazards associated with the use of materials, equipment, and/or operations detai

7、led or referred towithin this report. Users of this NACE International report are also responsible for establishing appropriate health,safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary,to achieve compliance with any existing applicab

8、le regulatory requirements prior to the use of this report.CAUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACE Internationalreports are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACEreports are automatically w

9、ithdrawn if more than 10 years old. Purchasers of NACE International reports mayreceive current information on all NACE International publications by contacting the NACE InternationalMembership Services Department, P.O. Box 218340, Houston, Texas 77218-8340 (telephone +1281228-6200).ForewordThe purp

10、ose of this technical committee report is todiscuss the state of the art of internal corrosion-monitoring techniques for subsea equipment includingproduction and injection systems (e.g., wells, jumpers,manifolds, flowlines, risers, storage systems, pipelines,etc.). It is intended to be useful for en

11、gineers involvedwith subsea production systems.Corrosion monitoring at the terminus of a pipeline, inthe topsides facility, or at the onshore facility is beyondthe scope of this report. Information on the techniquesand methodology for such facilities, including informationon the traditional intrusiv

12、e techniquescorrosioncoupons, linear polarization resistance (LPR) probes,electrical resistance (ER) probes, and potentiodynamicscans, can be found in NACE Publication 3T199.1A distinction between inspection and monitoring ofsubsea systems exists. Inspection techniques are usedinfrequently to determ

13、ine the corrosion condition of asystem. Thus, inspection can give information on thewall thickness of the system, telling whether either mild orsevere corrosion has occurred. Corrosion monitoring isused frequently or continuously and can therefore beused as a control tool for modifying system parame

14、ters. In this technical committee report the main attention isfocused on those methods with sufficient sensitivity andfrequency of measurements to be classified as corrosion-monitoring techniques. However, inspection techniquesthat are beneficial for determining the useful life andsafety of a system

15、 are also described.This technical committee report was prepared byNACE Task Group T-1D-46 (formerly T-1C-24), a com-ponent of Unit Committee T-1D on Corrosion Monitoringand Control of Corrosion Environments in PetroleumProduction Operations. It is issued under the auspices ofGroup Committee T-1 on

16、Corrosion Control in PetroleumProduction._* Chairman Mike Joosten, Conoco Inc., Ponca City, OK.NACE International2Table of ContentsGeneral2Definition of Terms.2Subsea Corrosion Monitoring: Present IndustryPractice3Permanently Installed Monitors.3Ultrasonic Testing Methods.4Field Signature Method.4Su

17、rface-Active Techniques.5Intrusive Monitoring Methods7Monitoring Methods Utilizing Inspection Tools7In-Line Inspection Tools7Direct and Electronic Calipers8Magnetic and Electromagnetic Techniques,Flux Leakage, and Eddy Currents9Ultrasonic Testing (UT) Techniques.10Inspection Techniques Using Cameras

18、and/or Video Recorders.11UT Measurements by Divers and ROVs.11Corrosion Monitoring at Terminus, Topside,or Onshore13References13GeneralCorrosion monitoring techniques can be divided intointrusive and nonintrusive methods. Intrusive methodsare those that access the inside of a system. Nonintrusive sy

19、stems do not require internal access. This distinction is particularly critical in subsea usebecause of the difficulty in using intrusive devices inunderwater locations, especially at greater depths.Nonintrusive monitoring systems include the fieldsignature method, thin layer activation, and fixedul

20、trasonic testing (UT). These systems and others arethe focus of this technical committee report.Definition of Terms(1)(1) Words shown in italics are those that are defined elsewhere in this section.(2)American Society of Mechanical Engineers (ASME), 345 East 47th St., New York, NY 10017.Anomaly: Any

21、 kind of imperfection or defect that may bepresent in the wall of a component.Camera Pig: A configuration pig that carries a video orfilm camera and light sources for photographing theinside surface of a pipe on an intermittent or continuousbasis.Corrosion-Resistant Alloy: An alloy that displayssubs

22、tantial resistance to corrosion in the environment ofinterest.Data Analysis: The process by which indications areevaluated to classify and characterize them asnonrelevant conditions, pipeline components, anomalies,imperfections, defects, or critical defects.Defect: An anomaly for which an analysis,

23、such asASME(2)B31G,2indicates that the pipe is approachingfailure as the nominal hoop stress approaches thespecified minimum yield strength (SMYS) of the pipematerial.Flux Density, Magnetic: The strength of a magneticfield, expressed in flux lines per unit area.Flux Leakage Field: The magnetic field

24、 that leaves orenters the surface of a part as the result of a discontinuityor a change in section.Imperfection: An anomaly in the pipe that will not resultin pipe failure at pressures below those that producenominal hoop stresses equal to the SMYS of the pipematerial.Indication: (1) Any measured si

25、gnal or response froman inspection of a pipe above the normal baseline signal.(2) Measurements made during monitoring of cathodicprotection systems.Injection System: All portions of the physical facilitiesthrough which injected fluids or gases move duringtransportation, including pipe, valves, and o

26、therappurtenances attached to the pipe, such as compressorunits, metering stations, regulator stations, deliverystations, holders, and other fabricated assemblies.Inspection: (1) The process of examining a pipe using anondestructive testing technique to look for anomalies orto evaluate the nature or

27、 severity of an indication. (2) Theprocess of running a configuration tool or an in-lineinspection tool through a pipe to detect anomalies.NACE International3Instrumented Tool or Pig: A vehicle or device, whichcontains sensors, electronics, and recording or outputfunctions integral to the system, us

28、ed for internalinspection of a pipe. Instrumented tools are divided intotwo types: (a) configuration pigs, which measure thepipeline geometry or the conditions of the inside surfaceof the pipe, and (b) in-line inspection tools, which usenondestructive testing techniques to inspect the wall ofthe pip

29、e for corrosion, cracks, or other types ofanomalies.Magnetic Flux: See flux.Monitoring: Measurements or periodic inspections madeat selected locations.Pig: A generic term signifying any independent, self-contained device, tool, or vehicle that moves through theinterior of the pipeline for the purpos

30、e of inspecting,dimensioning, or cleaning. (Also referred to as a“scraper.”)Pipe: The steel pipe exclusive of protective coatings orattachments.Pipeline: That portion of the pipeline system includingthe pipe, protective coatings, cathodic protection system,field connections, valves, and other appurt

31、enancesattached or connected to the pipe.ROV: Remotely operated vehicle.Subsea Corrosion Monitoring: Present Industry PracticeThe complexities of the conditions for subsea oil andgas production as well as changes in the operatingconditions have generally resulted in the application ofcorrosion monit

32、oring. The choice of subsea monitoringequipment is usually the result of considering three vitallyimportant aspects: cost, reliability, and accuracy. Inac-curate data or false indications can be costly to verify. Past experience has shown the reliability of downholeequipment (casing, tubing, subsurf

33、ace safety valves,mandrels, nipples, etc.) to be of paramount importancebecause of the cost of subsea workovers. The bestmethod for preventing corrosion-related workovers is pro-per initial design, with selection of a suitable corrosion-resistant alloy (CRA) or an effective corrosion controlsystem.

34、At present, downhole corrosion monitoringmethods are readily available, but have generally notbeen considered necessary by the industry when propermaterials selection is made. A similar argument can bemade for subsea equipment such as wellheads,christmas trees, subsea chokes, etc. For production and

35、injection equipment, such as pipelines, flowlines, andrisers not constructed from CRAs, monitoring equipmentis used in corrosive environments. For production andinjection equipment constructed from CRAs, corrosion-monitoring equipment is not typically used.Corrosion monitoring of subsea systems is s

36、till atechnology in its infancy. For that reason in-lineinspection tools and other methods have been used forthe evaluation of subsea production and injectionsystems, while corrosion monitoring is used at an above-water location topside or onshore. Today, subseacorrosion monitoring is mainly based o

37、n inference fromdata obtained at the line terminus. NACE Publication3T1991describes the techniques and methodology thatare relevant for surface corrosion monitoring.Permanently Installed MonitorsCorrosion monitoring is used in a subsea system todetect, predict, and prevent corrosion failure with its

38、 con-sequent safety and financial implications. Monitoringprovides the assurance that the corrosion-mitigationsystems, such as inhibitors, are doing their job.3The general philosophy of corrosion monitoring isthat multiple techniques are used to both complementand check each other. The overall cost

39、of a completecorrosion-monitoring program is lowit is trivial com-pared with the cost of undetected corrosion.A typical approach to defining a corrosion-monitoringprogram for a subsea application is to:(a) Consider the various techniques and methodologiesavailable. (b) Define the type of information

40、 required to determineacceptable operation of the corrosion-mitigation system.(c) Determine the required resolution based on responsetime.(d) Define the required system reliability.(e) Define the location(s) for the probe(s). A method to verify the information received from amonitoring system is vit

41、al because the cost of remedialactions (replacement) can be substantial. Some mon-itoring devices measure only a small area in comparisonwith the entire surface area and corrosion in otherlocations is inferred from those data.A limitation of traditional corrosion-monitoringtechniques in subsea appli

42、cations concerns commun-ication with the surface. However, with the developmentsin electronics, signal transmission, and data processing,the availability of subsea corrosion-monitoring techniquesNACE International4is expected to increase in the coming years.The following paragraphs describe some of

43、themonitoring techniques applicable for subsea. Thetechnologies described are those being used and/ortechnologies that are emerging for subsea use.Ultrasonic Testing MethodsSummaryUltrasonic methods are most commonly used forinspection purposes to detect and characterize internalmetal loss. Manual m

44、ethods are the most common, butautomatic systems are also available. Application ofsolid coupled probes on a North Sea permanentinstallation in 1984 was the first use of the ultrasonicmethod for subsea corrosion monitoring. Flexible probearrays are also available. This discussion is limited toperman

45、ent installations used for monitoring. Principles of OperationUltrasonic probes emit sound waves that arereflected from other surfaces (anomalies, the oppositewall, etc.). The time from the emission of the sound waveto its echo reflection back to the point of origin isrecorded and processed to deter

46、mine wall thickness. Applications to date have focused on the use oflongitudinal waves for measurement of wall thickness. The accuracy of the measurement is approximately 1% ofthe wall thickness.ImplementationThe solid couple is welded to the pipe to create arugged, permanent installation. The trans

47、ducer is fullyencapsulated and connected to the electronic packagethrough an insulated, sheathed cable. The maximumoperating temperature for the solid coupled probes is250 C. Data retrieval is possible through conventionalhard-wire links, hydroacoustics, and electrohydraulics. Typically, a number of

48、 probes are used to providemeasurements at several points. Flexible probe arraysare mounted with adhesive.Benefits(a) Uses existing technology.(b) Data analysis is straightforward and easilyinterpreted.(c) No maintenance.Limitations(a) Response time is longer than for other corrosion-monitoring tech

49、niques.(b) The hardware is susceptible to corrosion unlessfabricated from corrosion-resistant materials or alternate(applicable) corrosion-control methods are used.(c) This technique depends on base line data on theoriginal wall thickness and the results of previousinspection measurements.(d) The area monitored with this technique is essentiallyequal to the surface area of the transducer(s).(e) Inaccuracy in the measured thickness may increaseover time due to piezoelectric aging at elevatedtemperature.Field Signature MethodSummaryThe field signature method (FSM)