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ID1<Flff fgJfl" 1 <l1t <t>T ~ ~ om·· ~ ~ it J ' 4\li!i{J\iii 4i~<l!ifil'i i 3CT\M· it om: \1ilfol01 I c;-lff<lT /'>I <J fof 01 <$ 'fi1l('f i !:ti it <t>J1 ~ <t>J1 1 <l1t I <t>T 3101~mn r J ~ Rlfc«;r $~lf.'t<Jfl•I it II illl't01 ~ ti <i ft'! (1 !ITT" it $<11lf.il<4~JI it fg , ~ ~ ~ C(>l IOJi I + <t>H <t>J1 om <t>J1 M 1 <l1t 'liT ~ <t>H 1 <l1t <l'T .mm<f J J PETROLEUM AND NATURAL GAS REGULATORY BOARD NOTIFICATION NewDelhi, the 5th November, 2012 F. No.,mfraJIM11!1I;PL/1'12010.-ln exercise of the powers conferred by Section 61 of the PetroleumID'Td'NatUF!iltemi·Regulatory Act, 2006 (19 of 2006), the Petroleum and Natural Gas Regulatory !Bmlrd hereby makes the following regulations, namely :- •
1. Short title and commencement.
( 1) These regulations may be called the Petroleum and Natural Gas Regulatory Board (Integrity Management System for Natural gas pipelimes) Regulations. 2012.
(2) They shall come into force on the date of their publication in the Official Gazette.
2. Definitions.
( 1) In these regulations. unless the context otherwise requires.- ( a) "Act" means the Petroleum and. Natural Gas Regulatory Board Act. 2006;
(b) "Board" means the Petroleum and Natural Gas Regulatory Board established under sub-section ( 1) of section 3 of the Act;
(c) "natural gas pipeline" means the pipeline as defined under I.he Petroleum and Natvral Gas Regulatory Board (Authorizing Entities to Lay, Build, Operate or Expand Natural gas pipelines) Regulations.
2008;
(d) "0peratm" mec:ms an entity that operates natural gas pipeline network with the authorization of the Boord;
(e)"risk" means the risk as define'd under the Petroleum and Natural Gas Regwlatmr.y Board (Codes of Practices for Emergency Resp0nse and Disaster Management Plan (ERDMP) Regulations, 2010;
(f) "risk analysis" means the risk analysis as defined under the Petroleum and Natural Gas Regulatory Board (Codes of Practices fmr Emergency Response and Disaster Management Plan (ERDMP) Regulations, 201 O;
35 36 THE GAZETTE OF l\IDli\ . r>: '" '
(g) "risk assessment" rneans the risk C'<; : . ,,, •J··1oiv·sis •:"s C:e under the Petroleum and t~ai"urai Ge : >:' ,Jchry 0c<J; r:: (Ccc:, '· -:: :
Practices for Emergency Respoi ;se c~r , 1,, ·<-_,·:-~!:-,; --.11c,;n-.-~:~J()fl1ent ~i;;::~n (ERDMP) Regulations, 2010:
(h) "risk managemenf' mecns t~1t· ! is'< :·1-:-~'.:- - _;c, ;~.:: .:;:. c0f;ne--j L'· the Petroleum and Nutural Gos f;·-' Practices for tn .. ~er:3ency Responsf- or .. - ~'.:; ,·~_·_, ~· ,:~n·::-.1:::1 ... ::rn:-::;1--\i (ERDMP) Regulations. 20 IO:
•
(i) "spur-line" means a pip2:ir,c '" :: -· Natural Gas Regulatory Boero "cc:··-, -,,, ' and Petroleum Products o 1d k:
2010:
(j) "Subject Matter Expert (SV1E)" .-n-s:: ., knowledge and experience: !r, '"· · represents as per ASME B 31 G:
(k) "right of use (ROU) or right of ,., c·v , .
portion of land within which the :.· acquired the right through the ;:;>0·.:. · accordance with the agreernen' v .. i;·;
having jurisdiction over the lone: lu pipelines:
(I) "integrated surveillance syslern' rn";<i"' for third party encroachment oc1iviliio'.- ,( - optical fiber cable. micro\vaves one ,,_. f:,Jii:c: os cc:-Yn-1ur.:c::: · • systems and could be integroterJ w:11· ' ·
(2) Words and expressions used and net or0 ::. :n defined in the Act or in the ru!es or regc:!cf have the meanings respectiveiy ossigne~' , 1·•c;-· 'n ,,_.,, ··ct o rules or regulations, os the case :nov tie.
3. Applicability.
These regulations shall apply lo all the ent:ties 'cy'nu. l:i<Jilding. opsrc1 11 ·c:;: -~· expanding natural gas pipelines.
4. Scope.
These regulations shall cover all the existing and new m1t:Jrai gas transff.issic,r:
pipelines. spur lines. sub-transmission pipelines (ST!0 U and dedicated oiqc::-,, _,,_ This includes the associated facilities required fo, ;:c;1,sprc;'cr:c-r1 of nckJ·C· ~%~····~"' ~"~'~1rrt~·4 l .••... ·. .• ·~""-·'" :~.: '"··~1·~;m~ :. .. . . .. .:··~· · .u······ 37 "'="=11fcf u~h:.pipelines th~l is ferminats. interrnffi:!iate pigging facilities. compressor stations, s~ctl:)nolizln~:i vo!ves etc.
The molerio\ and ~pc: :ih··:itior:s followed shall be in accordance with ?etroieum 011d l\alurol Gas Regu!atory Board (Technical Standards and Specifications including Safdy Standards for Natural gas pipeline) Regulations.
2009.
11) Th,.::se regu1etion~ ou:line the basic features and requirements for developin'J and irnple!T1en!•ng an effective and efficient integrity management p!a1"1 f<)'.' riah.Jrot gas pipf3!irie system.
\c; evn!ucio risk associated with natural gas pipelines and 'Alsctiveiy alioccie resources for preventioQ. detection and :"ni;igoiion ocli.'ilies:
(o) improve 1he safety of natural gas pipelines so as to pro'tect the pf'r:.onnci. property, public and environment;
(c) i1cve slreomiined ond effective operations to minimize the probat,iiity of Natural gas pipeline failure.
The develotJrncni ci,-,d •rnpl8rnentntion of Integrity Management System for the nokirai go'> P!c~Jeiir:es ciK1ii be os described in SCHEDULE-1 to SCHEDULE-10 of ti:U$e regulafi.0~~~;.
( i) C orr,plionc:cJ tc 1he provisions of these regulations shall be done tillO')Gh impl•;:;cnentaiion schedule as described in these regulations al Schedule-7 and Schedule-8 in conjunction with Appendix-II.
(2) ln case of any shortfall in achieving the implementation schedule of lnteqrity Vc;nagemen! System as specified in these regulations. the ·~ en lilies shall be liable to face the following consequences, namely:- ····
(i) the entity shall be required to complete each activity within the specified lime limii and if !here is any deficiency in achieving in one or more o! the activities, the entity shall submit a mitigation piun within lime limit for acceptance of the Board and make good ali short comings within the time agreed by the .Board. If the 38 THE GAZETIE OF INDIA : EXTRAORDINARY [PART Ill-SEC. 4] entity fails to complete activities within the specified time limit by the Board. relevant penal provisions of the Act shall apply:
(ii) in case the entity fails to implement the approved Integrity Management System. the Board may issue a notice to defaulting entity allowing it a reasonable time to implement the provisions of Integrity Management System. In case the entity fails to comply within the specified time. the relevant provisions of the Act and regulations shall apply.
B. Reqvirement under other laws.
It shall be necessary to comply with all statutory rules. regulations and Acts in force as applicable and obtain requisite approvals from the relevant competent authorities for the natural gas pipeline.
9. Miscellaneous.
(l ! Through these regulations the uniform application of Integrity Management System is to be ensured for all natural gas pipelines.
(2) Entity operating and maintaining natural gas pipelines shall have the qualified manpower as per three tier structure as indicated in Appendix-IV.
(_3) These regulations either on suo-motu basis or on the recommendation of concerned sub-committee of natural gas pipelines shall be reviewed by the Board.
Ht. Power. kt remcwe difficulties.
In the event of the problem faced by the entity in implementing the provisions contained in these regulations. the entity may approach Board for necessary dispensation.
. OBJECTIVE SCHEDULES (see regulation 6)
SCHEDULE-1 The objective of Pipeline Integrity Management System is to maintain integrity of natural gas pipelines at all times to ensure public safety, protect environment and ensure availability of pipeline to transport gas without interruptions and also minimize business risks associated with.accidents and losses. The availability of the lnte9rity Management System will allow professionals and technicians engaged in integrity tasks to have clearly established work aims and targets in the short. medium and long term, which undoubtedly will enhance their efficiency and satisfaction to attain them.
[ 'lj]lJ 111~1!1US 4] The Integrity Management System will eriable the na<twrol gas pipelir.1e transporter to select an identified system for implementation such th'at the Integrity Management System will be uniform for all natural gas pipeline entities within the country. · An effective Integrity Management System shall be:
• Ensuring the quality of natural gas pipeline integrillly rn all areas which have potential for adverse consequences.
• Promoting a more rigorous and systematic management of natural gas pipeline integrity and mitigating the risk;
• Increasing the general confidence of the public in too o.peration of natural gas pipeline.
• Optimizing the life of the natural gas pipeline wifh the inbljj/t inciden-t investigation and data collection including review by th'.e enti'liy.
SCHfDULE-2 INTRODUCTION TO THE INTEGRITY MANAGEMENT SYSTEM UMSl
2.1 Every natural gas pipeline oper9tor's primary focus shall be on opera!ion and maintenance of natural gas pipeline in such a way that it would continuously provide un-interrupted services to customers wiffn u.trrnm.t reliability and safety without any untoward incident which con adveESely impact the environment.
2.2 A pipeline Integrity Management System shall provide a comprehensive and structured framework for assessment of pipeline condiliil!lfl, likely threats. risks assessment and mitigation actjons to ensure safe ood incident free operation of the pipelin~ system.
2.3 Such a compr-e-hensfwe integrity management system shall ~¥ comprise the following elements:
• Integrity Management Plan (IMP): This encompasses collection and validation of data. assessment of spectrum of risks, risk ral!\king ..
assessment of integrity with respect lo risks, risks mitigation, upctation of data and reassessment of risk.
• Performance evaluation of IMP: This is a mechanism to monitor the effectiveness of integrity management plan adopted and for further improvement.
• Communication Plan: This covers a structured plan lo regulate information and data exchange within and amongst the internal and external environment.
39 I I I ' J I i . ~::.:,f;.t~~-;:;t-it:~'M7tJ~t\L~~V!Jifl!£~1tt'·1:;t:tz1#Aiif,:~·t;\~~,~ : 11· +:
• · MdftGgeMent of Chanu« This lithe pt~ss to incorpcrote the system ·~· chOr'lges (technical. ptlysital. ptocedUrol and organization changes~ into integrity management · pJlatt · to update · · the integrity mcmageme1·,t plan. c ·.
• Quality Control: This is the proc.e.ss to estabiish th~ requirements of quality in execution of lhe processes detineCf' in ·the integrity management plan.
Note: These ele. have further been detailed in Schedule-ti.
· - SCHEDULE""3 PHCRlPUON•Gl.;NAJUBAL GAS PIPELINE ~Y-SlEM
3. 1 PtJY$!CAL. DE$CRIPl!ONi Description of r1oiural gos pipeiine should lnch.:rde s/5l3clfic description of the pipelines cornoressors. valves with respecffo design specifications. length. major irdallot<ons detrnls such as:
3.2 :r.:
3. 1.1 Trunk Pipeline
3. l.2 Spur-pipelines
3.1.3 Sect1onollzing Valve Stations · 3:1.4 Intermediate Pigging Stations ... 3.J.5 lcip-Off Stations .. ·· ·~.a~i ~i Compres.sor Stations
3.l.7 Control Stations.
3, l .8 Electrical System depending upon Captive power generation or Grid-pov,cer ..
~,;],9 C~thodic. Protec.lion System . -.&3••h10 .SCAD A.
3.1.11 Safety Eqvipments . 3. l .12 Delivery Stations QIHJll DE$CRlf.I!ON:
, ' - :< - - -, - - C'' '
3.2.1 ROU DetQils-ROU width and co.nstroinls. it ony ·· .
3.2.2 lntertaces With other opetcitors · bci.l!tie~ '" pit;.<"'!in·•". ,; •m:t.
3.2 •. 3 .l;listoricat background pf Jhe nqtuial gas pipeline. und rnajor modifications and additions c.~rr1ed oul in !he~ystem if ony:
3.2.4 List of the consumers served by 1he pipeiir1e5'.
, ,,.,,~.2.5 lnspectionupdales; .
'- . 'i l 1' . ·,.
i ~· ., ' I r f t i I i !
t I t ' , I ' i ;
" I !
_j 1-i1111 Ill ''~ 11 ·~ Ii . ----------===--- ·--- -
3.2.6 1nc1de11t reporting:
3.2.7 Staten1erit ot cornp 1 icrnce with Petroleum and Natural Gas ReguiCJ '.c1ry BC)Ol'(j includin·1 Sot"ty Regulations. 2009· (Technical '.3tandords ar.d Specifications )1oncJcirds tor Natural Gas Pipeline)
3.2.8 Statutory compliances.
SCHEDULE-4 SELECTION OF APPROPORIATE INTEGRITY MANAGEMENT SYSTEM
4.1 Integrity Managem~nt System for natural gas pipelines could employ either a performance based Integrity Management System or a prescriptive type Integrity Management System.
Whereas, natural gas pipeline industry has gathered a reasonably good experience of pipeline operations and as such pipeline industry is fairly mature. a performance based Integrity Management System are appreciated globally.
However, where pipeline systems are in developing stage, a prescriptive type Integrity Management System is recommended. Whereas, the performance based Integrity Management System recognizes the experience of the entity which has been operating the pipeline but the prescriptive type Integrity Management System is more rigorous as it considers the worst case scenario of the failures in the pipeline systems and, therefore, worst case scenario for mitigation.
4.2 Though subsequent schedule in these regulations apply to both prescriptive and performance based type of Integrity Management System, present regulations mainly focus on prescriptive aspects in absence of adequate historical Integrity Management System data.
4.3 A prescriptive type of Integrity Management System mandates the implementation of an established process for addressing the risks, their consequences and proven methods for mitigation. It also mandates the in-house development of Integrity Management Plan and Management of Change pertaining to technical aspects. Based on the development of gas pipeline industry in India till date, the preparation of prescriptive type Integrity Management System has been considered for implementation to all natural gas pipelines iri India. Further, as the natural gas pipeline industry matures and gathers sufficient records .or data as per the requirements orescribed in the Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications Including Safety Standards for Natural gas pipelines) Regulations, 2009, a review mechanism may be considered by the Board for recommending a Performance Based Integrity Management System for Natural gas pipeline.
4232 Gl/2012-6 -C INTEGRITY ASSESSMENT TQOLS Some ot the too:- for Integrity assessrnent.•me :providc-d>t:iet©w. mlrre·~or should use as niony tools necessary to cc hi eve !he IMS-tor:imatimrait!llJill:Sl!DiJDelrne.
11 may be noted 111ai the baseline :.u1a for ·;-•~<Aic meilllll!l-rrrt·'!!lnID0lc!Llne a,,ailoble will1 [,;e operolo• ma reauy-reckomer:
5.1 In-line Inspection In-line inspection (Ill) is an integrity asse~t·•l'lltdll1111mi•lll!BIBiilat0:Jtm:limrte;CliJll1d preliminarily chorac terize indications such •ms. metalJ1mi&rllJIHuilEibu0ttnl&tlilnm;mi&-ll as ext e rna I and in I e rn al corrosion in a pipe line. •A'll:/lil\Elmllt.'!61 :s WMwmlUl!lill!!U;D,Jl!ffem In t e gri ty for Natura/ gas pipelines" pr m<iaies <Glctalilimr.rol~[!!Jl!iilltmmtie Clll1llll!liiJlmffime <in- 1 i ne inspection.
Internal inspection tools shall have =pmitnlltt.y tJ;lf ;<lllml!!JQttim:g ~illm <mmd deformation anomalies viz. dents. g~.•~Jlf~ (Int ell ig en t PiQg i ng) or any other 1tanllm1lltlv!!wrtttnmt-; <nmnr1>jjlJMiii&iiBtl:clml'lillRl!ehl111f integn1y assessment equivalent •to ·t~li!tTe ·-f111!1jj9i91illilll1flritrn "liliCU@!l!Jhe -..wttlln provisions of Petroleum and Natural Gas-~bdbvi\ll'lftmmM!flMidlduiill!Dlmtm••tu•ils and Specifications including .Safety :&tmmil!mallis dlmr~IJl!llDl&<lll&IPtbllilllll!!i) Regulations, 2009 may be employed as:h!lt~~!sJ&ml&l!!tfillllllltlliubri:I.
5.2 Cath-a•cdk ProtecH~n .CCPliMuWMm
(i) Pipe to £oil ·Potential Survey/ Ctased d•nlie'r,i;wl ·f.1~,rtmgi:m;g Survey.
(ii) Transformer Rectifier Unit/ Cat•ho-dic'Prm~~m·lf.l'~l\y Module - current and voltage monitnring 111lfl!e\ttlfl:axm
(iii) Coating Health Surveys (Current Attenuciffikwn :T!fl'rt)~ Curren! Voltage Gradient survey ar;id Peor-smn)
(iv) Pipelirne llllterference Survey
5.3 Survemarrce Various ellBolive sur·veillance methods ·are beir;ig ·~ •£1!15•allmact· !ll!rtegrity assessment :t(!)IDls . .Based upon •the experience®11Td•r~merr11iill•AA!!Jl!llf1llent. one or multiple •tools mciy be followed ·by the op:e~mtor;-s011lllecorili1Lnfitrme<l!tetllliled ri~ under:
I. Patrallling IiGtteUmll.:iufAAey of .the Rrght<of ldsewhiclil-:imtllwlliestkt~lk for emuring ol.ecir Ni511Dility .of iilB.!IMt cof IWmytRrght <di ·il!is:e .. <J:JC:cess to maintenance crew along •the -R~ht •()f.'Wm#fi~cohl!liie;-'>Vm"-'eitc;rcatians ~)llell~Hlmt!ii;Ttiii;oalem, helps to.- observe surface conditions, lewlt!B@lu; mtM!rui;;.tll!>m, activity perrormed by external agencies, ern!lllliiililiiilli1•1U11Rtt~w~<1J!lrll:l;al'IY oftrer factors affecting the safety and ~l!!m1afrtlti'lffipi~lme, Also, pa.trolling ground survey may be done for rrrmimlellll!llllllJ!e«Dit'<illltililiJ!!m1ime markers, kilometer posts and other specific irmlimn:diiD1'Tlfll'llllMC!llll!m@rlttre: pipelime. This may also include:
(ill NJ@IMI·· p:<nll'ollil'lg by Line walkers or alternative security S!i!li'l«eillllim«:e- system where the pipeline location is Vl!IJliralr\©IDle;,frc:mn security point of view
(iij). Rl!!Jl!rt' 6WLJ.ge_ tr-ocking through satellite imaging methods f'©Trcritimol·stretches of natural gas pipeline system (llifi" Aer•iaJi survey of Right of Use at critical and in--accessible stretches e,g, hilly regions and Ghat sections etc.
If. ·•for. critlcal.she:t1t:hes:
The ab~sysJile:m11,.,mClllftUse vari©w&. types of detection systems which may be ernpl0ye:<d1'ft1m c~>- c©ll!rrtry pifDelimes based on the system requirements. The geAer>©Jrd.l!l.~Ja.onsu.c.::i1 :J<o:lecliomsystemare given below:- l. Filrren Optico Sysrerrn: Jt;is detection system works on seismic vibrafion prirr<riple which rrnafi.- te employed for any kind of terrain and soil and is usefui !cir pip:relimes crossings. This system is primarily used for buried pipelinesc.
2. Gr-Oli!mi:di· Sel!f6'«m S):~ This detection system also works on 1cisrn;r.
vllnna:ll1!1111l'pmii>le:i!001B1•ama:li•rnoy also. be used for any kind of terrain and ,,.,;1 Gr©w.rmdise1118Qrs~11m· rne.y: be used for buried pipelines as well as abovr· gr:oll!mtdl•piJ!lellmes.
3. Raldi:!lrr· b«lSl!llD·. d.elte"lt.titi'J.m. system: This system works on the principle of mic1<0.• W©r«e.,re~i·cm11.· It is applicable for pipeline terrain where large ui:l©luimili011r-·i11·rE!!iWltr:l'e'di However. this may be useful for any kind of soil amdiJOll@mm>pwaoHd1rorabove ground pipelines.
4. Fema::e·s~une: dlillli®1=e£S system: This system works on the principle c/ vi©J!llltiil:!llT" olr·tmlll.m't!l:tonw am'l'.di is useful in inslallation along the riipelir•e s~: Tit!$· o~r Wlffi!l· o~ this system could be for pif"JEoline <. orridor sa©"l!lrilll'@l pi~li11t111v illll' v0nw sel'lsitive areu where !hero ore oftoch ""/ !~lOff·~, lfltt§Miun•••a& Vlllogens or.mtg®'leral. pwblic along fhe righl of way shall be mode uw.
of the: p€lssil!Jle consE:>quences of nafurn 1 uus leaks by pro•1iding u lis I of Do1's amd Don' ls. Safely awareness among !he admini1fration and !o·::c::'
44 THE GAZETTE OF INDIA : EXTRAORDINARY [PART 111-SF.c. 4) public ma,• be created as per the disaster management plan in accordance with the provisions of Petroleum and Natural Gas Regulatory Board (Codes of Practices for Emergency Response and Disaster Management Pla:i). Regulations. 2010.
5.4 HYDROTESTING Hydro testing is appropriate for integrity assessment when addressing certain threats at the pre-commissioning stage itself al lest pressure specified in the Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safely Standards for Natural gas pipelines) Regulations.
2009.
5.5 DIRECT ASSESSMENT AND EVALUATION Direct assessment methods Iha! include visual Non-Destructive Testing (NOT) examination lo reinforce and validate findings from in-line inspection and other incidental findings. like during incidental pipeline exposure. pipeline damages and other maintenance activities may also be employed as an Integrity Assessment tools. External Corrosion Direct Assessment (ECDA). Internal Corrosion Direct Assessment (ICDA) and Stress Corrosion Cracking Direct Assessment (SCCDA) are the available tools for direct assessment and evaluation.
5.5.1 External Corrosion Direct Asse~sment (ECDA) can be used for determining integrity for the. external corrosion threat on pipeline segments. The ECDA orocess has the following four components:
(L · Pre assessment- incorporating various data gathering. database integration and analysis
(b) Identification - using either tools or calculations to flag possible corrosion sites. or calls. based on the evaluation or extrapolation of the database
(c) Examinations and evaluations - excavation and direct assessment to confirm corrosion al the identified sites and remediation as provided in Schedule 6 of these regulations.
(d) 'OSI-assessment - lo determine if dig call decision are taken on a , oeline segment. However. Call decisions are driven by various t0-:iis. technologies. or engineering evaluations. but are higrly dependE 11 -:·n the level of experience and expertise utilized.
w1·,11e implementing E> le· -,: :_ c1 osion Direct Assessment if the pipe is exposed.
the operator is advise, d lo conduct examinations for threats other than that for external corrosion al• ) (iike mechanical and coating damages).
['lJll 111-~ 4]
5.5.2 Internal Corrosion Direct Assessment (ICDA) can be used for determining integrily for !he infernal corrosion threal on pipeline segments. The ICDA process has !he following four componenls.
(a) Pre-assessmenl
(b) ldentilicalions
(c) Examinations and evalualions ( d) Post-assessment
5.5.3 Stress Corrosion Cracking Direct Assessment (SCCDA) can be used for determining integrity for the stress corrosion threal on pipeline segments. The SCCDA process has the following four components.
a) Pre-assessment b) Identification c) Examinations and evaluations d) Posl-assessment
5.6 Thickness assessment and periodic review against basellne values For all sections of the pipelines above ground, all pipeline skids and pressure vessels, a periodic thickness assessment and comparison wiih baseline values may be done and employed as lntegrily Assessmenl fool.
The operalor of a pipeline syslem shall develop a chart of most suiled integrily assessmenl fool or method and assessmenl inlerval for each threat/risk and further develop appropriate specifications and qualify control plan for such assessment. After eslablishing effecliveness of assessmenl. the inlerval of assessment may be further modified subjecl to any olher code requiremenl such as Petroleum and Nalural Gas Regulatory Board (Technical Slandards and Specifications including Safety Standards for natural gas pipelines) Regulations,
2009. A suggested char! is placed al APPENDIX -Ill
5.7 Pipellne equipment Health Monitoring Pipeline equipment such as main line sectionalizing valves, olher valves, pig launching and receiving facililies etc. may be checked periodically for !heir operation.
5.8 Review of existing pipeline Clau Locations:
If class location changes are perceived oue lo demographic changes along !he existing pipelines, population density sur•;,• .1 may be carried oul to ascerlain the changes in class localion.
45 TlfH· GAAETTE OF JNJ)ll\. FX I JV10RDJN.\RY :I',. Ill '· ii ro:.:Oldlttlres> the cnoroges in class location of a pipeline from lower to higher c1a&s; the provisions mentioned in Technical Standards and Specifications includlITTg! S~ Sromdtlrtds/ ASME B3r8 shall be considered. The one or multiple foflowins mitigmtion measures may also be considered till· same is mitigated as per Te<r:.hnical,Starroords and Specifications inctud.ing· Safety· Standards I ASME B
3T.8:~rements - aj. Se11:ti'orr to be· declared as vulnerable and frequency of patrolling to be irl'!CTemsed as per new class location.
b) lnflelHl!Jemt pigging/Direct Assessment freqwencies to be increased.
c) CF iTIOl'liloJlil'lg, frequencies to be increased including provision of continuous dmlln/PSP logging at the location.
d} Corrosion monitoring: probes to be installed to monitor the corrosion rote.
e~ Provisiom of carbon fiber wrapping/ composite sleeves/ concrete slabs.
S CHE:D.Ul.&-6:
DUJ.'GNftt& AP·Plf·C:.AlttE INTEGRllY MAJ!t'AGl'MNT SYSTEM FOR' THE r+Anlll!Ai GAS PlffUN'E:
AH opem:itors of existing and new natural gas transmission and distribution pipelimes shall dev.elop an integrity management programme comprising the necessary plans. implementation schedule and assessment of its effectiveness in Ol'der to emure" safe and reliable operation of the pipelines. It is recognized that thec compJll!!!\ensi>re pipelime integrity managemen1 programme is based on contimwows,.eiaer:dse of extensive data collection. assimilation and analysis.
Furtl'Ter; al'l' dn~ management programme can be devised on specified mettwds,, prm::edlimes ai!lddime· intervals for assessment and analysis or on the basis of pel'lu1rnanc:e of the programme with regard to efficacy of integrity asses&r:rremt pllmn. its results and mitigation efforts. For operators implementing an integrity meincrgement programme in the absence of base line and perfofmance data. it may become imperative to adopt a prescriptive integrity mal'lagememt prograrnme irnitlolly.
All na1ltm:il gas pipelines and associated facili#es installed as a part of pipeline shall·oo covered in pipelime integrity management plan. The cycle of basic processes ot integrity management Plan is illustrated in Figure 1 and further detailed hereunder:
Revjew of.Integrity Management System-as per Schedule 9 No Initial.data .gathermg .-and·-l'e..,iew Thraat-ldenhficalion evaluated > Yes ·-Consequen13es1ar.id ·Impact ,Aftalysis Risk Assessment I 'Evaluation ·Integrity Assessment ~ 1 Mitigal1on and Responaes ·IData-.updation,and :jnlegrat1on Da.ta,relel:e"d ~e>:design and engineering, construction, pre-CO'rrmrtissiclnhcrg and coffi1'1:1issioning of pipeline assets, operGJtion and maintenance snoll 47 48 THE GAZETTE OF INDIA : EXTRAORDINARY IP ART 111-SEc. 4] be gathered and reviewed along with post-construction operational and integrity assessment data gathered to identify the potential threats along the pipeline system. Operational and integrity assessment data will be continuously updated while performing various activities along the pipeline such as patrolling. aerial surveillance. Cathodic Protection (CP) monitoring. monthly maintenance of equipments etc. and records maintained either hard or soft options.
6.1.2 Threat Identification:
Gas pipeline incident data analyzed and classified by Pipeline Research Committee International (PRCI) represents 22 root causes for threat to pipeline integrity. One of the causes reported by the operator is "unknown". The remaining 21 threats have been _classified into three groups based on time dependency and further in to nine categories of related failure types according to their nature and growth characteristic as below:
(I) Time Dependent Threats:
' 1) External Corrosion 2) Internal Corrosion • Internal corrosion due to off spec. gas* also to be considered 3) Stress Corrosion Cracking *Refer the Petroleum and Natural Gas Regulatory Board (Access Code for Common Carrier or Contract Carrier Natural gas pipelines) Regulations. 2008.
(II) Stable Threats:
4) Manufacturing related defects . i. Defective pipe seam ii. Defective pipe 5) Welding /fabrication related i. Defective pipe girth weld ii. Defective fribrication weld iii. Wrinkle bend or buckle iv. Stripped threads /broken pipe /coupling failure 6) Equipment i. Gasket 0-ring failure ii. Control/relief equipment malfunction ['IFT 111-lli"S 4 ] 49 iii. Seal pump packing failure ·- ============o...=== iv. Miscellaneous (Ill) Time independent Threats:
7) Third party /mechanical damage:
i. Damage inflicted by first. second or third party (instantaneous /immediate failure) ii. Previously damaged pipe (delayed failure mode) iii. Vandalism· 8) Incorrect operational procedure 9) Weather related and outside force:
i. Weather related ii. Lightening iii. Heavy Rains or Floods iv. Earth Movements Besides the above, certain other threats may be applicable based upon the land pattern.
i. Creek area effects ii. Muddy land effects iii. River bed movements
6.1.3 Consequence and Impact Analysls:
Once the hazardous events ore identified, the next step in the risk analysis is to analyse their consequences. that is. estimate the magnitude of damage lo the public, property and environment of all the identified threats. These consequence may include leak, fire. explosion. gas cloud etc. Consequence estimation can be accomplished by using mathematical models e.g. consequence modelling.
ldenliftcatlon of High-consequence area (HCA): Locations along the pipeline system meeting the criteria for High-Consequence Areas are identified.
Generally, these are high-population-density areas, difficult-to-evacuate facihl es (such as hospitals or schools). and locations where people congregate (such as places of worship. office buildirigs, or fields). Clause no. 3.2 of ASME B 31.8 S may be referred for detailed information regarding potential impact area.
6.1.4 Risk assessment specific to pipeline system
6.1.4.1 Developing a Risk Assessment Model: Risk assessment process identifies the location-specific events or conditions. or combination of events and conditions that could lead lo loss of pipeline integrity. and 4232 Gl/2012-7 50 THE GAZErfE Of INDJA: EX~Y ~-==:::::::=::·· -- -- - - ---...;:.·_:_--=====--=:::::.:
provides an understanding of the llketihood an'd C0flS6qlJJEmces of these events.
The risk assessment has the following objectives:
• Prioritization of pipeline sections/segments for scheduling integrity assessment and mitigation plan • Asse~sment of the benefits derived from mitigation actiorn • Determination of the most effective mitigoiion m~m f01' the identified threats • Assessrnent of the integrity impact from modllietl' il'lSpeGWM 1¥'\ifE!l'vds • Assessment of the use of or need tor Elftefli~ ~fidn methodology • More effective resource allocation Pipeline sections may be prioritized for integrity ~essmenf based on severify of composite risk due to oil threats. The compOSife risk vd!Ue for particular pipeline section is product of relative likelihood of failure ood con~equences ol'fogether due to all applicable threats. Risk priority shd!\' be e!~ '°' ~ne sections observed with high risk to or~ize foo ~ ~'- me w~ may simpiy i:.Je categorized as high, medum. low (or l, 2. J) & !alf}m r~. t :'
differentiate the priorities among various sedftmS.
Following approaches for risk assessment and ~ffftaf~· ~ be ~j -7:
deemed suitabfe lo !he Operators:
a) Utilizing the services of Subject Mo1fe" E:xperf~ (SMtsy b) Relative Assessment Model c} Scenario -Based Model d) Probabilistic Models The risk asses~ models mentioned above have following c,m1rn6n' fedfUres.:
(a) They ~potential events or conditions that coulu frncor&n system integrity;
(b)They evtlloote fiketlhood of failure and consequences:
(c) They pefmfl· ml< ranking and identification of specific threats tr,"< I ! • ·;;'Jrily influence 01' drfVe fhe risk:
(d) They lead fo fhe identification of integrity assessment and/01 ·· : •-.::in option;
le) They prbvide for a data feedback loop mechanism;
(I) They provide a structure and continuous updating for risk reassessments Risk assessmenf considering the likelihood and consequences through risk assessment ~ooches may not consider the extent of failure fhaf is leak or ru1->''-'"'· If fdi!Ufe cailtrOI be identified as leak or rupture while assessing the risk thrc»:gh any of me Ubove mooels, o worst case scenario may be considered.
.
l>.t.U ---§~-----~:
lhe risk assessmen1 is continuous ano! repe1i1ive process. System wide risk assessment shall be carrieo! out at least every year by pipeline o,perators through any of the methodology mentioned above after incorpor.0ting qnd updating the recently captured data in risk model such as:
• lnar;$a5:e in Operating Pressure, average temperature/dew point of gas, water content in gas beyond acceptable limits.
• Chg,nges in Right of Use conditions like development of encroachments, increase in third party activities/ population density, major washouts.
• Pipeline Leak/rupture history.
• AGlaii,tion of new /expansion of the existing railway/road/waterway crossings.
• Changes to pipeline cathodic protection levels due to external interference problems.
• Any o+her issues which may al!ect the integrity of pipeline.
• The results of previous integrity assessments.
The risk assessment may be performed earlier if any new threat is perceived.
The risk assessment process and method shall be reviewed and updated periodically to achieve the objective of pipeline integrity management plan consistently.
The result of risk assessment shall be arranged in descending order for each section for prioritizing the section for conducting integrity assessment after selecting the GIPP~QPriate integrity assessment method based on most significant threats to pc;irticular section.
6.1.5 Integrity Assessment:
A plan shall be developed to address the most significant threats and risks as per previous seclfon .and determine appropriate integrity assessment methods to assess the integrity of the pipeline segment. The following methods can be used for Integrity Assessment:
• Hydro tcesHn@I before commissioning at test pressure as per T 4S standard • lnline inspection (ILi) • External & Internal Corrosion f)irec.t A.,5essment(ECDA/ICDA) • Various forms of pipeline 1urw;iil(lnce and monitoring e.g. patrolling lntegratec::l Surveillance System (ISS) etc.
Brief description of various Integrity Assessment methods has also been provided in Schedule-5 of these regulotiom.
THE GAZETTE Of INDIA : EXTRAORDINARY IPART 111--Sioc. 41 Selection of appropriate integrity assessment method shall be based on most significant threats to which particular segment are susceptible. One or more integrity assessment methods can be used depending upon the threats to particular segment of pipeline.
The operator of a pipeline system shall develop o chart of most suited integrity assessment method and assessment interval for each threat and risk. The operator shall further develop appropriate specifications and quality control plan for such assessment. After establishing effectiveness of assessment. the interval of assessment may be further modified subject to the requirements under the Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for Natural gas pipeline) Regulations. 2009 and other relevant Regulations. A suggestive chart is placed at Appendix -Ill.
6.1.6 Mitigation and Response (Repair and Prevention) After the completion of assessment like inline inspection and coating health surveys, the results shall be evaluated and the necessary repairs and preventive actions shall be undertaken to eliminate the threat to pipeline integrity.
Immediately upon completion of integrity assessment. a comprehensive schedule of repair shall be prepared. All anomalous conditions discovered through the integrity assessment shall be evaluated and classified under the following three categories based on severity of defect. Mitigation action (repair and prevention) shall be undertaken to eliminate an unsafe condition to the integrity of a pipeline or to ensure that the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment.
(A) MHlgatlon through Repair Actions:
At the time of establishing schedules. responses shall be divided into three groups and repair actions shall be as follows:
(a) Immediate repair conditions:
Such indication shows that defect is at failure point. This shall include but not limited to any corroded area having - i) Metal loss equal to or more than 803 of wall thickness.
ii) Predicted failure pressure less than equal to l . l times the maximum allowable operating pressure (MAOP) as determined by ASME B3 l G or equivalent.
iii) Metal loss indication affecting a detected longitudinal seam. if that seam was formed by direct current or low frequency electric resistance welding or by electric flash welding.
[ '1flT 111 - c;pr-6 4 ) iv) Any indication of adverse impact on the pipeline expected to cause immediate or near term leaks or ruptures based on their known or perceived effects on the strength of pipeline which include dents with gouges.
v) Any near term failure indication.
(b) Scheduled conditions:
Such indication shows that defect is significant but not at failure point.
Following indications shall be examined within one year of discovery:
i) A plain dent that exceeds 63 of nominal pipeline diameter for pipeline operating at or above 303 of Specified Minimum Yield Strength (SMYS).
ii) Mechanical damage with or without concurrent visible indentation of the pipe.
iii) Dent with cracks.
iv) Dent that affect ductile girth or seam welds if the depth is in excess of 23 of the nominal pipe diamete'.
v) Dents of any depth that affect non ductile welds.
• For more information on scheduled conditions." Repair Procedures for Steel Pipelines" paragraph 851.4 of ASME 31.8 may be referred.
(c) Monitored conditions:
Monitored conditions show that defect will not fail before next inspection.
Such indications are the least severe and will not require examination and evaluation until next scheduled inlegrity assessment interval provided that they are not expected to grow to critical level prior to the next scheduled assessment.
(B) Mitigation through Preventive Actions:
The pipeline operator shall develop scheduled programme for monitoring the integrity of the pipeline to prevent from time dependent and independent threats to support the integrity assessment and mitigation plan.
The monitoring scheme and frequency should be· decided by the pipeline operator subject to compliance of Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for Natural gas pipeline) Regulations. 2009. The few schemes are as follows:
(a) Patrolling of pipelines and associated facilities
(b) Maintenance of Right of Use and inspection of Crossings 53 54 THE GAZETTE OF INDIA : EXTRAORDINARY \l'AKl 111-.J.-._. -.J
(c) Pipeline Cleaning I Pigging
(d) Inspection of cathodic protection system
(e) Coaling Survey (Closed Potential Logging I Direct Current Voltage Gradient I Pearson/Current Attenuation Test)
6.1.7 Update. integrate and review data:
After the initial integrity assessments are completed. the results shall be maintained in soft. hard or both versions which will be used for future risk and integrity assessments in addition to operational information that is recorded on continuous basis for assessments and implemenling risk mitigation plan.
6.2 Performance Evaluation Plan:
Every pipeline operator shall· define suitable performance indicators which can be monitored to give a picture of the integrity levels of various aspects of the operator's pipeline assets. Refer ASME B "31.8S table no 8 and 9 for finalizing performance measures and performance matrix respectively. Monitoring of these indicalors on a periodic basis against pre-defined largels helps to assess the effectiveness of Integrity Management programme. Performance indicator measures should be selected carefully to ensure that they can reasonably indicate the effectiveness of programme and health of the assets.
An operator can evaluate a system's integri_ty ·management programme performance within their own system and also by comparison with other systems on an industry-wide basis.
Such performance evaluation should consider both threat-specific and aggregate irnprovements. Threat-specific evaluations may apply lo a parlicular area of concern, while overoll measures apply to all pipeiines under the integrity managemenl programme.
Performance indicator measures may measure either or all of the oelow as applicable:
(i) Process measures e.g. number of damages per excavation notification received.
(ii) Operational measures e.g. number of significant In-line Inspection anomalies.
(iii)Direct integrity measures e.g. number of damages per km. of pipeline length.
A performance indicator may be either leading or lagging indicator. Lagging measures are reactive in that they provide an indication of past integrity management programme performance. Leading measures are proactive in that they provide an indication of how the plan may be expected to pertorm.
l 'lfl1 111 lsitrs 4 ] "''-=--~--~======================
6.2.1 Performance Measures Pe-rformance measures serve as a tool for evaluating the success of the pipeline Integrity Management System. The performance measures have been developed as a method to gauge the extent to which the pipeline Integrity Munogement System goals have been met. Performance results demonstmte \',i •<:tlit~r integrity management activities are appropriate or require imrmwements. The results may be evaluated annually by the pipeline opemtors. at which time the appropriateness of each performance measure will L),1 ossessed. Some of the goals as part of performance measores are illu~tmled below for reference. The operator may set their own goals rJnpe1 iding on priorities and specific problems.
55 i-1~;~~~-i~~a~-n-p-ip_e_l_in_e_G_~-i~-~---to---So_i_I -Po-te_n_t-ia-l-~---P~v~·9·-.
(}'SP) within acceptable limits I - - -- - --- -- --------- ·--- -- ------·---l f.xec~tion of In-line Inspection pigging _________ As_q.i_!?Q!icabl~------- _ _J ~eaK_(l~ and ruptures __ _ Number . 1 _N_u_m_b-erof trair\i-ng_a_n_d_aw-_ a-r-e-nessj uevelopment. Training and Awareness p~o?ra_m_m __ e_s___ ~~gr~~~mes conducted 1n a Y.:?!_ J 1 No Right of Use encroachments Number of encroachments I '--·- ------~----·--------------------- ........ -1 In addition to the above performance measures. the pipeline Integrity System Monitoring Report includes the following:
• • Patrolling Inspected vs. Planned .
Key Integrity issues such as encroachments.
constructional deficiencies. mitigation plan and any issues.
restoration .
operational • The number of Integrity Management System required activit1ll!> completed.
• The number of defects found requiring repair or mitigation.
• The number of leaks reported.
For performance medsures relating to damage events. the following points are documented in the Operator's Damage Prevention Report:
• The number of third party damage events and near misses.
• The number of pipeline hits by third parties due to lack of no tifica lion.
• Aerial surveillance and patrolling reports.
ll11: GAl'.J:l IE 01- INl)I..\ : F.\ I R.\OIWI\ \1'1
6.2.2 Continuous Improvement The Integrity Management System shall be continuously evaluated and modified to accommodate changes in pipeline desig•1 and operation changes in both the physical and regulatory environment in which the system operates and new operating data or other integrity related information.
Continuous evaluation is required to make sure that the programme takes appropriate advantage of improved technology and 1ha1 the programme remains integrated with the operator's business practices and effectively supports the operator's integrity goals.
lntegri1y Managemen1 System shall be evaluated and reviewed as per the frequency described in Schedule-9 of these regulations. Issues that would typically be reviewed may include. but are not limited to:
·• Performance measures.
• Testing and inspection successes and failures.
• New threa1 iden1ification.
• Root cause analysis of pipeline breakdowns and accidents.
• Process enhancement/ changes (Management of Change).
• Recommended changes for the Integrity Management System.
• Additional training requirements necessary to support ln1egrity Management System.
• Public awareness programme.
• Inspection 1ool performance (whenever applicable).
• Inspection tool vendor performance.
• Alterna1ive repair methods.
• Staffing for inspections. 1esting and repairs.
• Pas1 and presen1 assessment results.
• Dalo in1egration and risk assessment information.
• Addi1iona! preventive and mitigating actions.
• Training needs ot O&M personne!.
• Addi1ional items as necessary lo aid in the success of 1he IMP programme.
Based on results of the internal reviews. integrity assessmen1 and mitigation programme shall be improved and documented.
[ '1Jll lll-1'i"S 4]
6.3 Communication Plan:
This provides a framework for developing and implementing a written internal and external communication programme for operators of natural gas transmission lines and distribution pipelines. All pipeline operators shall develop and implement a communication plan to disseminate the ·integrity management efforts undertaken by pipeline operator and also to receive internal and external information or input. This· programme must address intended audiences, message content, communication, frequencies and methods and programme evaluation. The information received through external/internal communication should be considered for risk assessment.
integrity assessment and mitigation. The communication plan typically comprises, establishment of external and internal communication system as follows:
6,3.1 External Communication:
This should cover the communication plan with external agencies, which are not directly related with operator's business, for propagating information regarding presence of pipeline location, damage preventing actions, company contact information for reporting leakage and informing before carrying out any excavation etc. The various means such as web site, warning boards, pamphlet distribution, street p~ays etc. can be utilized by operators for this purpose. The following external agencies may be targeted:
(/) Land owner and tenants along the Right of Use.
(II) General Public near pipeline route.
(Ill) Public officials and statuary bodies other than emergency responders.
(IV) Local and regional emergency responders.
6.3.2 Internal Communications:
This should cover the dissemination of the information to employees and persons involved in operation and maintenance of pipeline system regarding integrity management programme to understand and comply with the programme objectives and requirements. Such a plan is also expected to fully cover the flow of information and controls in response to emergencies.
6.4 Management of Change:
Pipeline systems and the surrounding environment in which pipelines operate are often dynamic and need changes depending upon operational or any other requirement. Prior to implementation of any changes to pipeline system, a systematic process shall be adopted to ensure that prospective changes 57 58 TIIE GAZETTE OF INDIA : EXTRAORDINARY (PART llf--SEC. 4] (such as design, operation, or maintenance) are evaluated for their potential risk impacts to pipeline integrity including impact on environment. All natural gas pipeline operators shall define a management of change plan in integrity management programme to at least address the following:
(i) Reason for Changes
(ii) Authority to approve changes
(iii) Analysis of implications (threat and risk analysis)
(iv) Documentation
(v) Communication of changes to affected parties After implementation of changes, they shall be incorporated, as appropriate, into future risk assessment to ensure that th.e risk assessment process addresses the systems as currently configured, operated, and maintained. The results of the Integrity Management Plan's mitigation activities should be used as feedback for systems and facilities design and operation.
Changes to the pipelines could affect the priorities of the pipeline Integrity Management Plan and the risk mitigation measures employed. Any change in design basis, process or operational issue that can affect the risk rating has to be routed through Management of Change.
6.5 Quality Control All the entities shall prepare and maintain documented procedure and records as per the requirement of this standard which can also be made part of existing quality programme (e.g. IS0-9001-2001) maintained by the entities. The following activities shall be made part of quality control programme:
{i) Identifying and maintaining the documents required for Integrity management plan, procedures and records. This includes both controlled and uncontrolled documents.
(ii) Defining roles and responsibilities for implementation of programme, documentation etc.
(iii) Reviewing of Integrity fv\anagement Plan and implementation of recommendation at predefined interval.
(iv) Training and awareness of persons implementing the lntegr1ty management plan.
{v) Periodic internal Audit of integrity management plan and quality plan.
(vi) Documentation of corrective actions taken or required to be taken to improve the integrity management plan or quality plan.
['II'! Ill-~ 4] Internal Audits of the Pipeline Integrity Management System shall be performed on a regular basis. The purpose of the audits is to ensure compliance with the policies and procedures as outlined In these regulations. Recommendations and corrective actions taken shall be documented and incorporated into the Pipeline Integrity Management System.
Internal aurnh are conducted by the audit group nominated by Head of the Operations Team of the entity at least once in a year. Internal audits aim to ensure that the Integrity Management System's framework is being followed.
The following essential items will be focused for any internal and external audit of the entire Integrity Management System:
4232 Gl/2012-9 • Ensure that the Baseline Plan is being updated and followed and that the baseline inspections are carried out.
• Verify qualifications of O&M personnel and contractors based on education qualification (Appendix-IV), formal training received through in-house or external programme, demonstrated practical skills, and experience records in the relevant areas. Refer ASME 831 Q for guidance.
• Ensure adequate documentation is available to support decisions made.
• Determine if annual perrormance measures have been achieved.
• A written integrity management policy and programme for all elements • Written Integrity Management System procedures and task descriptions are up to date and readily available.
• Activities are performed in accordance with the Integrity Management System.
• A responsible individual has been assigned for each task.
• All required activities are documented.
• All action items or non-conformances are closed in a timdy manner.
• The risk criteria used have been reviewed and documented.
• Prevention. mitigation and repair criteria have been established, met and documented.
THE liAZETIE OF INDIA : EXTRAORDINARY
SCHEDULE 7 APPROVAi. OF INTEGRITY MANAGEMENT SYSTEM CIMSl:
[PART RI-Se:. 4) A Natural gas pipeline Integrity Management System is a management plan in the form of a document that explains to operator's employees, customers, regulatory authorities. etc .. as lo how the operator and its assets are managed.
by stating:
(i)· who is responsible for each aspect of the asset and its management;
(ii) what policies and processes are in place to achieve targets and goals:
(iii) how they are implemented;
(iv) how performance is measured and;
(v) how the whole system is regular1y reviewed and audited.
For the first time the approval of the IMS document shall be done by the Board of the entity. While during review to be done every three years. the approval shall be done by CEO I Full time Director of the company and all levels of management shall comply with its contents. Necessary awareness shall also be created within and outside the company regarding benefits to the society for up keeping of the pipeline system for all times to come.
Preparation of the document shall be done in following three stages and six steps:
1 .1 MANAGEMENT APPROVAL:
• Step#1: Prepared by In-house team or Consultant • Step#2: Checked by In-house team Head or Consultant head s Step#3: Provisionally approved by Head of Operation team of the entity • Step#4: Conformity of IMS document with the Regulation by Third Party Inspection Agency (TPIA)
7.2 ACCEPTANCE BY PETROLEUM & NATURAL GAS REGULATORY BOARD (PNGRB} • Step#5: Acceptance by the Board
7.3 APPROVAL FOR IMPLEMENTATION • Step#6: Approval of Integrity Management System document for implementation by the Board for the first time and approval of subsequent periodic review by CEO or Full time Director of the entity.
Note: A certificate regarding the approval of Integrity Management System document duly approved as specified at clause no. 7.1 above shall be Su~"lilled lo the Board that the Pipeline Integrity Management system is in line with the re'-luiremenfs of the various regulations issued by the Board from time to lime and has been approved by the CEO or lull time Director of the company.
, [ 'lflT Ill-~ 4] -·--
SCHEDULE-8 IMPLEMENTATION SCHEDULE of lntegrltv Management System:
Sr. No. Activities ·Time Schedule 1 Compliance with Petroleum and YES/NO confirmation Natural Gas Regulatory Board within 1 month from (Technical Standards and date of notification specifications including Safety of these regulations Standards for Natural gas pipelines) .Reoulations. 2009 2 Preparation of Integrity 1 year from date of Management System document and notification Of these approval by Head of Operation regulations team of the entity.
3 Conformity of Integrity Management 3 months from the System document with regulation by approval by Head of Third Party Inspection Agency. Operation team Of the entity.
4 Submission of Integrity Management 1 month from the System document lo Petroleum and conformity of Natural Gas Regulatory Board Integrity Management System by Third Party lnsoection Aaency 5 Approval for implementation by the Within 3 months from entity the acceptance of Integrity Management System document by Petroleum and Natural Gas Requlatorv Board 6 Start of I mplementalion Immediately after approval at Sr. No. 5 above 7 Submission of Compliance Shall be submitted Statement to Petroleum and Natural within 1 year to Gas Regulatory Board Petroleum and Natural Gas Reaulatory Board Note: Steps for Implementation to be followed as described In Schedule-7 61 I TIIE GAZETIE OF INDIA : EXTRAORDINARY [PART Ill-SEC. 4)
SCHEDULE-9 REVIEW OF THE INTEGRITY MANAGEMENT 'SYSTEM
9.1 Periodicity of review of Integrity Management System Entities shall review their existing Integrity Management System every 3 years based upon the:
(i) Revised Baseline data
(ii) Critical Inputs from various departments
9.2 Review of lntemal and Externc:il Audit There shall be a system for ensuring compliance to the provisions of these regulations by conducting following audits during operation phase:
(a) Internal Audit as per the checklist for natural gas pipelines provided by Petroleum and Natural Gas Regulatory Board shall be carried out by the management of operator every year.
(b) External Audit (EA) by third party. approved by the Board. as per the methodology specified by the Petroleum and Natural Gas Regulatory Board every 3 years.
SCHEPULE-10 Adequacy of Manpower positioned at different stage of project Entity will have to address the requirement of manpower for different stages of project, n..imely: Design. construction.
commissioning.. operation and maintenance.
The entity which is preparing Integrity Management System should address the manpower requirement for its present and future operations. Tile qv.alifica:Hol'l of such manpower shall conform to Appendix-IV.
[ 'lPI UI~11115 4] APPENDIX-I REFERENCES Reference documents of Standard Operation and Maintenance procedures related to Pipeline Integrity may be developed for use of O&M personnel. Some of them are mentioned below for reference:
SIN 1 2 3 4 5 6 7 • Petroleum and Natural Gas Regulatory Board {Technical Standards and Specifications including Safety Standards for Natural gas pipelines) Regulations, 2009:
• Petroleum and Natural Gas Regulatory Board {Codes of practices for Emergency Response and Disaster Management Plan) Reguiations, 2010;
• ASME B31.8-Gas Transmission and Distribution Piping Systems:
• ASME B31.BS - Managing System Integrity of Gas Pipelines;
• ASME B31 Q- Pipeline Personnel Qualification • ASME B31 G - Manual for Determining Remaining Strength of Corroded Pipelines.
• Gas Research Institute - 00/0189 - A model for sizing high consequence areas associated with natural gas pipelines APPENDIX-II CRITICAL ACTIVITIES IMPLEMENTATION SCHEDULE CRITICAL ACTIVITY TIME SCHEDULE Cathodic Protection (CPI lnsoection As per Petroleum and Pioaina/lntelliaent Piqoina Natural Gas Regulatory Surveillance Board (Technical Coatina Survey Standards and Hydro-testing Specifications including Safety Standards for natural gas pipelines) Renulations. 2009 GIS Maooina lmolementation 2 years Leak Detection Svstem lmolementation 2 years 63 THE GAZETTE OF INDIA : EXTRAORDINARY [PART Ill-SEC. 4) APPENDIX· Ill SUGGESTIVE CHART FOR SELECTION OF INTEGRITY ASSESSMENT METHOD• WITH RESPECT TO SPECIFIC THREAT Threat Group Threat Integrity Assessment Assessment interval Method• (A)Time-Dependent External Corrosion lnline inspection, Max.I 0 year** External Corrosion Direct Assessment Internal Corrosion Inline inspection, Max. I 0 year•• Internal Corrosion Direct Assessment Stress Corrosion lnline inspection, Max. I 0 year•• Cracking Direct Assessment (B} Stable a} Manufacturing Defective Pipe Seam Hydro-test (Post Before related defects Construction), Iniine commissioning or as Defective Pipe inspection and when required b) Welding I Defective Pipe Girth Fabrication related Weld .
Defective fabrication Weld Wrinkle bend or buckle Caliper Pigging I . Electronic Gauging Pi•<>ing (EGP) Stripped threads/broken Visual Examination I pipe Gas Leakage Survey c) Equipment Gasket I 0-ring Failure Visual Examination I Gas Leakage Survey Control I Relief Visual Examination I euuipment malfunction Gas Leakage Survey Seal pump packing Visual Examination I failure Gas Leakage Survey (C)Time-lndependent a)Third Party I Damage inflicted by Public Education (See Monthly /quarter! y Mechanical first, second, or third Communication Plan Damage parties (Instantaneous I & preventive actions), Immediate failure) Patrolling, ROW Maintenance, External Protection Previously da,maged Above + Leakage pipe (delayed failure Survey, Rehabilitation mode) Vandalism All above b)lncorrect Incorrect Operational Compliance Audits Operations procedure -· .. - wh~n I c) Weather Weather related Leakage survey, As and Related and Surveillance required Outside Forces Li11.htninl! Sunze diverters Heavy rains or floods Anti-buoyancy .inspection, Surveillance Earth Movements Strain monitoring, Leakaiie survev.
Creek Area Effects Surveillance, Pipe to As and when Soil Potential surveys required near creek, Leakage survey, Anti-Buoyancy Inspection, Integrated Surveillance Svstem Muddy/Marshy area Surveillance, Pipe to As and when effects Soil Potential surveys, required Leakage survey, Cathodic Protection monitoring, Integrated Surveillance Svstem River Bed Movements Surveillance, Pipe to As and when Soi I Potential surveys, required Leakage survey, Cathodic Protection monitoring, Anti- Buoyancy Inspection, Integrated Surveillance Svstem • Some of the Important lntegrtty Assessment Methods hove been briefed In Schedule- 5 of these regulations •• lnline Inspection frequency to be as per Petroleum and Natural Gos Regulatory Boord (Technlcal Standards and Specifications Including Safety Standards tor natural gos plpellnes) Regulations, 2009 APPENDIX-IV Minimum Quallflcatlon and Experience for fleld Personnel In Protect Phase gs well as O&M Stage Discipline Tier· I Tier-II Tier-ill Supervisor Level Operator Level I t Degree In Diploma In Mechanical !Tl with ot least I year Mechanical Mechanical Engineering + at least I experience in the relevant En11.ineerinu vear of Exnerience field of oneration Degree In • Diploma In Metallurgical IT! with at least I year Metallurgical Metallurgical Engineering + at least I experience in the relevant year of Experience in Engineering Pipeline corrosion control field of operation THE GAZETTE OF INDIA : EXTRAORDINARY [PART Ill-SEC. 4] Degree In l&C I Diploma In l&C I !Tl with at least I year Instrumentation Electronics Electronics + at least I experience in the relevant &Control Engineering year of Experience field of operation Degree In Diploma In Electronics JTI with at least I year or Communication Electronics & Electronics or Engineering+ at least I experience in the relevant Communication Communication field of operation Engineering year of Experience in SCAD A Degree In Diploma In Electrical IT! with at least I year Electrical Electrical Engineering+ at least I experience in the relevant Engineering year of Experience field of operation Fireman course passed and proficient in operation of Equivalent Degree Diploma In F&S fire water pumps and fire Fire & Safety In F&S Engineering I at least l tenders with heavy vehicles Engineering year of Experience driving license I at least I year experience in the relevant field of operation Diploma In Civil ITI with at least l year Civil Degree In Civil Engineering+ at least l experience in the relevant Engineering year of Experience field of operation Note: Each Natural gas pipeline shall have SME (Subject Matter Expert) having qualification in any of the discipline mentioned above witll minim11111.S ~ ofrele_"."~~-~-~~.!l.<;e, ..
RATAN P. WATAL. Secy.
[ADVT-111/4/hay./l 88/l 2] Prinud i,y the Manascc. (jovemmenl of India Ptm., Ring Road, Mayapuri. N;;w Delhi-1 lOOfl·I and P\Jblishrd by die Controller of Publicaucms, Delhi~t 10054 I Page 1 Page 2 Page 3 Page 4 Page 5 Page 6 Page 7 Page 8 Page 9 Page 10 Page 11 Page 12 Page 13 Page 14 Page 15 Page 16 Page 17 Page 18 Page 19 Page 20 Page 21 Page 22 Page 23 Page 24 Page 25 Page 26 Page 27 Page 28 Page 29 Page 30 Page 31 Page 32 Page 33 Page 34 Page 35 Page 36 Page 37 Page 38 Page 39 Page 40 Page 41 Page 42 Page 43 Page 44 Page 45 Page 46 Page 47 Page 48 Page 49 Page 50 Page 51 Page 52 Page 53 Page 54 Page 55 Page 56 Page 57 Page 58 Page 59 Page 60 Page 61 Page 62 Page 63 Page 64 Page 65 Page 66