Inspection and Testing Procedures Improve BOPs for HPHT Drilling

8/12/2019 Inspection and Testing Procedures Improve BOPs for HPHT Drilling

1/5

Blowout prevention(BOP) equipment forhigh-pressure, high-

temperature (HPHT) opera-tions requires consistent,thorough inspection andtesting procedures to main-tain high performance stan-

dards.A consortium of seven

Norwegian operators com-missioned WEST Hou Inc. toevaluate the parametersaffecting the safety and relia-

bility of BOP equipment forhigh-pressure, high-temper-ature operations. This studyalso analyzed several aspectsof BOP equipment for nor-mal temperature and pres-sure operations.

The study scope included

equipment manufacturingspecifications; temperature,pressure, and fluid effects onequipment; BOP stack con-figurations; and methods forinspecting, testing, andmaintaining well controlequipment.

The data come from auditsof BOP equipment on 25HPHT rigs operating in theNorth Sea and SoutheastAsia, investigations of stan-

dard-temperature elasto-mers in BOPs on 165 rigs,technical material from theoriginal equipment manu-facturers, extensive meet-ings with the manufacturers,and some operator experi-ences.

Overall, with few excep-tions, the study found that

BOP equipment built toAmerican Petroleum Insti-tute (API) specifications is fitfor purpose when it leavesthe manufacturer. After-ward, maintaining the high-performance standard is theresponsibility of the equip-

ment owner.A key finding of the study

was that equipment-specificinspection and testing proce-dures (ITPs) are beneficial tomaintain high performanceBOP equipment to an accept-able standard. Specificacceptance criteria for eachfield test are necessary.

TECHNOLOGY

Inspection and testingprocedures improve BOPs

for HPHT drillingMichael E. Montgomery WEST Hou Inc. Katy, Tex.

OGJ

16

12

8

4

040

Days exposedSource: Hydril Co.

Increaseinhardness,

%

Fig. 1

8 12 16

25C.

100C.

150C.

H IGH TEMPERATURES INCREASE ELASTOMER HARDNESS

Based on a presentation at the Inter-national Association of Drilling Con-tractors Well Control Conference ofthe Americas, Houston, Nov. 16-17,1994.

Reprinted from the February 6, 1995 edition of OIL & GAS JOURNALCopyright 1995 by PennWell Corporation


2/5

Equipment in use

Most BOP manufacturersfollow high-quality in-housestandards and API Specifica-tion 16A. Thus, BOP equip-ment comes from the manu-facturer fit for purpose.

Most problems occur withequipment that has been inthe field for some time, andnot with new equipment.The drilling industry does

not have a specification forBOP equipment repair. Usedequipment may not performlike new equipment, gener-ally because of a lack of thor-ough maintenance and test-ing. In some cases, the mostrecent repair may not haveused parts from the originalequipment manufacturer.

If equipment performancedoes not meet expectations,the problem usually resultsfrom a lack of detailed in-

spection and testing proce-dures (with specified accep-tance criteria) or a lack ofquality-control in some non-original equipment manu-facturer repair facilities.Adequate specifications andprocedures may not be avail-able for third-party mainte-nance personnel to inspectand test equipment.

This problem usually re-sults because the informa-tion is not available from themanufacturer, the informa-tion did not reach the serviceman on the rig, or the main-tenance staff did not know

the information was avail-able.

Technical informationOne of the largest obsta-

cles to proper BOP equip-ment maintenance today isthe poor availability of infor-mation. Some manufacturershave made an exemplaryeffort to publish engineering

bulletins to distribute theirtechnical information, and

the distribution of this mate-rial is an integral part of theirquality system.

Although other manufac-turers have much technicaldata in their files, they havenot been as diligent aboutpublishing these data. Thus,the information is difficult toretrieve or exists in a formatunsuitable for distribution tothe customer. Furthermore,many equipment manufac-tures have reduced staff dra-

matically during the pastdecade, leaving fewer engi-neers to produce technical

bulletins.After the first study meet-

ing for this project, onemajor BOP equipment man-ufacturer realized it neededabout 20 additional engi-neering bulletins to supportits equipment. This type ofreaction was common forother manufacturers as well.

Most equipment manufac-turers do not consider BOPequipment inspection stan-dards proprietary, but theydo need control over the dis-

tribution and revision ofinformation. Each companymaintains stringent practicesand procedures for the man-ufacturing process; however,in many cases the manufac-turers have not specified anacceptance standard for usedequipment.

Although modifying test-ing and inspection proce-dures for used equipment issubjective, improving the "if

it pressure tests, it's good"inspection philosophy will

benefit the industry.

Man on the rigThere are several reasons

why the man on the rig maynot know about new devel-opments with his company'sequipment, even thoughthose developments mayhave happened years ago:

The manufacturer's dis-tribution practices may be

poor.Sales of equipment be-tween drilling contractorsand trades between rigs cre-ate difficulty for the manu-facturers to know who is thecurrent equipment owner.

Problems exist within thecontractors' distribution andimplementation programs.

Maintenance staffIn some cases, the mainte-

nance staff did not know theinformation was available.Even if the information waspublished by the manufac-turer and distributed to the

current owner and rig, manyof the modifications and de-velopments may have oc-curred years ago, and recentpersonnel changes may re-duce the understanding ofsome equipment details.

Documenting changes and

making the informationavailable are among themost effective ways of im-proving equipment reliabil-ity. The use of inspectionand testing procedures(ITPs) for each componenton the stack can improvequality control. ITPs havetwo benefits: the quality isconsistent, and the criticalparameters only have to beidentified once.

Information transmitted to

maintenance staff in theform of ITPs should containthe following:

Inspection proceduresand acceptance criteria

The technical source ofcritical specifications.

Information used to in-spect and test equipmentcan come from a variety ofsources. Rather than manypeople being responsible forremembering what the infor-mation is and where to findit, it should be recorded in

the ITP.A procedure to keep the

system current.Once an ITP is written and

distributed, controllingchanges becomes instru-mental in keeping it current.A standard procedureshould be developed to dis-tribute new information tothe people who need toknow. With change controland new procedure distribu-tion procedures, a system

can be continually improvedwhen a new method is de-veloped or additional infor-mation becomes available.

Equipment performance

Because of the lack of fieldITPs for equipment in use,equipment owners must de-velop their own equipmentinspection and testing proce-dures. These ITPs shouldhave specific acceptance cri-teria based on the manufac-turers' recommendationsand be supplemented withexperience and good engi-

TECHNOLOGY

OGJ

700

600

500

0

Hang-offcapacity,

kips

Fig. 2

400

300

200

100

Fixed bore 5-in. variable bore 31/2-in. variable bore

183/4-in., 15,000 psi rams

Maximum

HANG-OFF TESTS WITH LOCKING SYSTEM ONLY

Manufacturers

A

B

C


3/5

neering practices.The industry can continue

to expect to be guided by themanufacturers. Because themanufacturers' capitalequipment sales and engi-neering support staffs havecontinued to decline over thepast 15 years, the contractorsand operators must use theirown engineering knowledgeto improve the reliability ofdrilling equipment. Relying

only on one's own experi-ence, however, does notallow a company to benefitfrom the experience andexpertise of the industry.

The manufacturingprocess has numerous quali-ty checks, inspections, andtests to ensure the equip-ment performs as required.The technical objectives ofthese tests lead to equipmentperformance criteria.

Marine riserThe following example,

using a marine drilling riser,illustrates the importance oftesting and performance cri-teria. Riser problems can sig-nificantly affect downtime.A 1987 Sintef (Foundationfor Scientific & IndustrialResearch at the NorwegianInstitute of Technology) reli-ability study reported risersas the second leading causeof equipment downtime onfloating rigs off Norway.Petrobras, in an independentstudy, found risers as a lead-

ing downtime cause in thedeep waters off Brazil.

The development of anadequate riser test proce-dure begins with an analysisof its operational require-ments, including the follow-ing:

Required surface finishof the Colmonoy No. 5 over-lay on the choke and kill linepins

Minimum allowable OD

of the choke and kill pinsAllowable choke and kill

box surface finish on the ODof the choke and kill seals

Minimum end float ofthe choke and kill lines (adynamic seal)

Different load limits ofthe telescopic joint in theextended and collapsedposition

Telescopic joint boltingrequirements (several stackshave been dropped because

of problems in this area),Manufacturers have madeonly a small portion of thisinformation available to theequipment owners for riserinspection. Thus, there arethree choices in the develop-ment of adequate testingprocedures:

Use new equipmentinspection standards onused equipment

Continue to use the pres-sure test as the only accep-tance criteria

Use good engineeringjudgment to develop mini-mum standards.

Although some companiesmight consider specific dataproprietary, such as dimen-sional data, no inspectionstandard would be accept-able without it.

With an industry averagefor subsea BOP stick down-time of 4%, continued use ofthe pressure test as the soleacceptance criteria is not themost economical choice.Thus, good engineering

judgment is a must in theabsence of specific manufac-turers' recommendations forcomplete inspection proce-dures to supplement thestandard pressure test.

All marine drilling risermanufacturers use Col-monoy No. 5 on the pins

because of the material'shardness and abrasion resis-tance. Riser manufacturershave not yet published spec-ifications for acceptable

choke and kill pin surfacefinish. Based strictly onexperience, WEST Hou'sprocedures specify 32 rms(root mean square) surfacefinish as acceptable. In ameeting for the Norwegianstudy, Greg Childs, drillingproducts manager for Coop-er Oil Tools, stated that 32rms was an acceptableinspection standard for aCooper riser in service.

Considering this technicalinformation may be the bestavailable, and all choke andkill pin designs operate onthe same engineering princi-

ple of a dynamic seal, thisspecification can be used asthe engineering standard forthe inspection of other man-ufacturers' risers. From theexperience basis for thisspecification and the verbalassent of one manufacturer,

it is logical to apply similargood engineering judgmentto other equipment.

Only mechanical criteriawere used in this example.The allowable operatingranges must also be speci-fied. An example of anallowable operating range isthe required hydraulic pres-sures for operating a well-head or riser connector.

The ITP should includesteps to lock the connector to

the test stump with 1,500 psiand 3,000 psi hydraulic pres-sure and record the requiredunlocking pressures for eachcase. Unlocking at too low ortoo high a pressure is equal-ly unacceptable. In the for-mer case, "back-driving" orunlocking of the connectorfrom external forces, such aswell bore pressure, tension,or bending, might occur. Inthe latter case, there may bedifficulty in getting the stackor lower marine riser pack-

age off the well. (Not beingable to disconnect when nec-essary for inclement weatheror a wild well is extremelydangerous.)

Pressure ratingsA demonstrated safety

factor is commonly includedin pressure ratings. Forexample, ram bodies aretested to 1.5 times the ratedpressure for pressure ratings

10,000 psi and twice therated pressure for lower rat-ings.

Not well known, how-ever, is that closed preventertesting on BOPs is only doneto the maximum workingpressure. (In this type of test,the well control equip-ment is in the closed posi-tion, and the seal is tested atthe rated pressure.) Thus,for a 15,000-psi ram, a safetyfactor for pressures greaterthan 15,000 psi may not beused, even in the manufac-turing facility.

The assurance that the

TECHNOLOGY

OGJ

700

600

500

0

Hang-offcapacity,

kips

Fig. 3

400

300

200

100

Fixed bore 5-in. variable bore 31/2-in. variable bore

183/4-in., 15,000 psi rams

Maximum

HANG-OFF TESTS WITH NORMAL OPERATING PRESSURE AND LOCKS

Manufacturers

A

B

C

D


4/5

rams are fit for purpose attheir rated pressure comesfrom proper maintenance,regular and comprehensivetesting, and confidence inthe manufacturer's designcriteria, fatigue testing, anduse of (American Society ofMechanical Engineers) de-sign allowables for workingpressure.

There is no industry stan-dard for pressure testing any

weld-repaired BOP equip-ment, even when the origi-nal equipment manufacturerdoes the work. Thus, theequipment owners musthave internal quality stan-dards to ensure safe opera-tion of repaired BOP equip-ment.

Temperature ratingsThere is no industry stan-

dard for high temperaturetesting. All of the full-scale

testing on ram preventers todate has used operatingpressure on the close side ofthe rams. One industry ex-pert said that this method isnecessary to achieve a sealand that well bore testing athigh temperatures will notwork without operatingpressure on the close side ofthe rams, using only the ramlocking device.

An operator should con-sider that well bore integrityof 5-in., high-temperaturepackers has never beenproven in the absence of op-erating pressure on the close

side of the rams. This issueshould be carefully consid-ered during well planning,prior to having to disconnectthe lower marine riser pack-age on a floating drilling rigor abandoning a rig.

Some ram packers are rat-ed as low as 200 F. OneSoutheast Asia operator,contacted for this study, re-cently "cooked" a set of 5-in.packers while testing a well

with a static bottom holetemperature of 268 F., indi-cating the importance ofknowing both the anticipat-ed downhole temperatureand the temperature ratingof the elastomers.

Many equipment-specificissues must be addressed fora stack dressed for a hightemperature well. Manystacks rated at 10,000 psi areused on wells in SoutheastAsia, and consequently the

rigs may encounter availabil-ity problems in acquiring thehigh temperature elasto-mers. Additional planning isnecessary to provide ade-quate lead time for acquiringthese high temperature elas-tomers. Some manufacturersdo not recommend resilientgaskets for wellhead connec-tors, and at least one manu-facturer provides a specialelastomeric compound forresilient gaskets used forhigh temperature applica-tions.

Another consideration isthat some fail-safe valves

cannot be upgraded for hightemperature applications.

BOP connectionsWashed-out ring grooves

on BOP connections cancause loss of containment.Manufacturers strongly rec-ommend that hubs orflanges have face-to-facecontact for surface and sub-sea installations, but there isnot yet an industry recom-

mended practice that speci-fies this contact. Also, anoperator or contractor needsto verify that the stress load-ing on the BOP kill andchoke line outlet is withinthe allowable range for thechoke and kill line connec-tions.

Washed out ring groovesare avoidable. The ITPsshould verify that face-to-face contact has beenachieved on all drill-through

connections and side out-lets. The ITP should specifyall aspects of bolt preloadprocedures, including retor-quing to overcome the ef-fects of relaxation embed-ding and lubricants.

Because of the special ex-posure to single-point failureloss of containment, sideoutlets beneath the lowerpipe rams on subsea stacksshould be given special at-tention. ITPs should specifyprocedures to verify that ex-ternal loads from well borepressure and bending loadsfrom the handling system

are not exerted on these con-nections.

ElastomersBecause elastomeric prop-

erties are particularly sensi-tive to the time of exposureto high temperatures, per-

formance tests are critical.Obviously, the standard ofwell bore testing should con-tinue to be used. However,annular preventers can also

be visually inspected anddrift tested 30 min after clos-ing pressure is released torequalify them for use on anadditional well. The combi-nation of these two tests isthe best available technologyto demonstrate an accept-able level of mechanical

properties remaining in therubber.When elastomers are ex-

posed to high temperature,the aging rate accelerates.When elastomers age, theylose their memory (ability toreturn to original condition).An increase in temperaturecan increase an elastomer'shardness considerably, sig-nificantly affecting its abilityto seal. Fig. 1, for example,shows how one nitrile elas-tomer's rate of hardness in-

creases by a factor of fourwhen the temperature is in-creased from 100 C. to 150C.

Specific tests (such as seal-ing characteristics tests forram preventers or drift testsfor annular preventers) can

be used to requalify elasto-mers prior to a drill stem testor during between-wellmaintenance.

There is an almost infinitecombination of drilling flu-

ids, considering the largenumber of additives on themarket and the temperatureranges of operations. It isvery difficult and impracticalto test all critical elastomerswith every drilling fluidcombination possible, espe-cially at all the possible tem-perature ranges.

Thus, when a drilling flu-id is selected for a program,the operator should ensurethat it is compatible with thespecific elastomers in the in-tended BOP. These tests can

be st be un de rt ak en byequipment manufacturers

TECHNOLOGY

OGJ

700

600

500

0

Hang-offcapacity,

kips

Fig. 4

400

300

200

100

Fixed bore

*Locking system only

5-in. variable bore 31/2-in. variable bore

183/4-in., 15,000 psi rams

Maximum

HANG-OFF TESTS OF MODIFIED RAMS*

Manufacturers

A

B

C

D


5/5

(as some already do) to doc-ument the effect of tempera-ture on the nitrile elastomersused as sealing components.

WearSubject to the pressure

ratings limitations noted

above, a 15,000-psi ram isgood for 15,000 psi andshould not be derated.

Shear rams, however, aremore affected by cavity wearthan pipe rams. Fortunately,with good well bore testingtechniques, ram cavity wearcan be detected before itleads to an unscheduled re-pair. Quality well bore test-ing techniques for early de-tection of problems pay offhandsomely, especially con-

sidering that much equip-ment in use is rather old andthat some ram blocks areharder than the cavity sec-tion.

BOP stackIn specifying a BOP stack

configuration, the operatorshould consider many fac-tors, including the follow-ing: stripping and hang-offcapability of the rams, shearcapability, choke and killoutlet placement, and use of

variable rams.Rig and equipment oper-

ating limits must be knownand taken into considerationduring well planning. Hang-off capability can vary great-ly, depending on the manu-facture date of the preventerand whether equipment has

been upgraded.The last major industry

study of BOP equipmentwas in 1985 by a consortiumled by Exxon Corp.; 1834-in.,

15,000-psi rams were stud-ied, and in some cases defi-ciencies were found. Onesuch case was with drill pipehang-off on 5-in. ram blocks.The hang-off capacitiesshow the maximum loadthat can be applied whilemaintaining well bore integ-rity. The study indicatedsome rams had discrepan-cies in hang-off capacity, de-pending on whether lockingpressure only or lockingpressure and operating pres-sure together were applied(Figs. 2 and 3).

A well plan must take into

account the worst possiblecasean event causing lossof operating pressure on theclose side of the rams (forexample, power loss, driveoff, anchors slip, loss of hy-draulic pumps, etc.). Thus,actual ram hang-off capacity

is critical.After these hang-off ca-

pacity limitations wereknown, some manufacturersmodified the designs of thepreventers. Three of the fourrams were retested, and thehang-off capacities im-proved significantly (Fig. 4) .

How can this informationbe used, and what questionsneed to bc asked?

Most high temperaturewells in Southeast Asia are

drilled with 10,000-psistacks, and a large amountof the equipment in the areawas purchased before 1985.

Has the manufacturermade design improvementsfor the hang-off capabilitiesof the 1834-in., 10,000-psirams, as well as for the ramswith other sizes and pres-sure ranges? (Note: Onlyone of the three manufactur-ers included in the test haspublished technical informa-tion about hang-off capacity

improvements, listing partnumbers, since the 19851834-in., 15,000-psi ramtests.)

Has the drilling contrac-tor purchased the equip-ment upgrades?

An operator must learnwhat the hang-off capacity isfor the rig hired and incor-porate this capacity into thewell plan.

During well planning, thefollowing should be consid-

ered:Are the manufacturer'sdata from estimates or actualtest results?

Ask for hang-off capabil-ities with operating pressureon the close side of the ramsas well as using the lockingsystem. If the operator onlyasks for hang-off capabili-ties, the number given mayonly be for operating pres-sure on the close side of therams.

Record the part num-bers of the ram blocks anddetermine their capacity.

When the string weight

reaches the hang-off capaci-ty, including a factor of safe-ty, those rams should beconsidered hang-off ramsonly and no longer sealingrams. The well plan shouldinclude a second set of ramsclosed for pressure integrity.

Manufacturers have notperformed stripping testswith high temperature pack-ers, so relying on old strip-

ping tests that used stan-dard temperature packersmay be misleading.

One manufacturer statedthat the required shear forcefor a given pipe grade andweight can vary by as muchas 60%. Therefore, the opera-tor should ask the manu-facturer for specific sheardata instead of generalyes/no" questions onequipment limitations.

Fail-safe valvesFor fail-safe valves, the

1992 Norwegian PetroleumDirectorate, "Regulations

Concerning Drilling andWell Activities," requiresthat "..the valves shall be ofa 'fail-safe closed' make andshall be capable of closingduring dynamic flow condi-tions."

There is no industry stan-

dard for this requirement;some operators regularly re-quire them while othersrarely do not. An operatorshould know the operatingcharacteristics of the fail-safevalves on the BOP stackused and under what flow-ing conditions they will re-turn to the closed position.

Most valves on BOPstacks are designed accord-ing to API Specification 6A.This specification does not

require the actuator openingand closing force to operatethe subsea valve when thevalve is at the most severedesign operating conditions.Valves for HPHT applica-tions, at a minimum, shouldhave this capability.

Consideration should begiven to upgrading existingequipment to conform withthe requirements of APISpecification 17D, "Specifi-cation for Subsea Wellheadand Christmas Tree Equip-

ment." API 17D, section908.2b (c) states: "Subsea ac-tuator opening and closingforce shall be sufficient tooperate the subsea valvewhen the valve is at themost severe design operat-ing conditions without ex-ceeding 90% of the nominalhydraulic operating pres-sure...."

The main question is:"Will a valve return to theclosed position under dy-

namic flow conditions?"This situation has not beentested by manufacturers, sohard data are not available.Some valve designs use well

bore pressure to assist thegate to the closed position(balanced gate valve), in-creasing the likelihood that itwill close under these con-ditions. Some valve designsdo not use well bore pres-sure assistance, however. Itis important to determine

beforehand what type offail-safe valve is used.

TECHNOLOGY

Michael Montgomery ispresident of WEST Hou Inc.,a BOP equipment consult-ing and training company.

He began his career on theDiscoverer III in Singapore as

one of the first subsea BOPengineers in the industry. Heconducts seminars on drill-through equipment and rig-specific training world-wide. Montgomery earned aBS in engineering from theTennessee TechnologicalUniversity in 1975. He is acoauthor of the U.K. Depart-ment of Energy GuidanceNotes, Section 43, which per-tains to blowout prevent-ers. He is a member of Amer-ican Petroleum InstituteCommittee 16 and is a task

group member for APISpecification 16, Drill

Through Equipment.

Montgomery

THE AUTHOR

Documents

Inspection and Testing Procedures Improve BOPs for HPHT Drilling