Copyright 2000, Society of Petroleum Engineers Inc.

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AbstractA study (JIP) on reliability of well completion equipment(Wellmaster Phase III) was completed by SINTEF inNovember 1999. This has resulted in a comprehensivedatabase on well completion equipment, with a total of 8000well-years of completion experience represented and morethan 1000 downhole failures included, given as input from the16 funding oil companies of this JIP. The database representsall categories of downhole equipment, from tubing hangerlevel down. The paper points towards the major contributors towell interventions and downtime, indicating industry averageand benchmark failure rates of the most vital completioncomponents. A historical evolution in reliability of Subsurfacesafety valves (SCSSV) is demonstrated, and the industry wideeffect of reliability improvements is shown through specificexamples. In the North Sea, reliability data has gainedwidespread acceptance for use in decision making. The paperlists several cases where reliability data of downholeequipment has been used with a major impact on fielddevelopment and subsequent operational expenditures.

1. Introduction

Reliability data has gained widespread use in the offshorebusiness due to industry studies like OREDA, Wellmaster andothers. The introduction of statutory codes and regulations in anumber of oil producing countries has also stronglyaccelerated this development. During the last decade, offshoreindustry managers have become increasingly aware of the

potential benefits which can be drawn from such databases.Some industry cases are now established which havedemonstrated the cost saving potential of such databases.

Examples of applications of reliability data are:

Risk and reliability studies LCC/LCP analysis Tender evaluations and purchasing decisions Rig contracting strategies Incentive based contract definitions Downhole barrier acceptance criteria definitions

Cautiously defined and consistent reliability data collectionrequirements is a prerequisite for successful reliabilitydatabases. The new ISO 142241 standard constitutes avaluable reference in this context.

The Wellmaster Phase III project objective has been tocontribute to improvement in completion equipment reliabilitythrough systematic collection, analysis and feedback ofreliability data to participating oil companies and equipmentmanufacturers.

The main deliverable from the project has been the newWellmaster data collection software for completions with anintegrated analysis tool, an updated database on completionequipment and reliability statistics and a summary report2 onmain findings.

Data analysis has focused on in-service equipment failures,defined as failures occurring from 6 days after landing thetubing hanger on the wellhead. Failures occurring prior to thatare defined as installation failures, and a fair amount of thesefailures have also been reported. All failure reported are alsolisted in a web-application where the Wellmaster JIP membercompanies have access.

SPE 63112

Application of a Completion Equipment Reliability Database in Decision MakingEinar Molnes, ExproSoft and Geir-Ove Strand, SINTEF Petroleum Research

2 EINAR MOLNES AND GEIR-OVE STRAND SPE 63112

Work process descriptionBy means of the Wellmaster software, a completion schematicis built to represent the completion configuration and givedetails on the equipment in the well. Failure data are captureddirectly via this schematic by pointing at the failed item andentering detailed data. Failure modes unique to each item arepredefined and can be selected when entering information onnew failures. In this way, a comprehensive and consistentdatabase can be generated. An integrated processing packageis then used to prepare a range of different reliability reportsfrom the database (MTTF, failure mode distribution, MTTW,run time distributions etc.). Upon reporting of failure data, ane-mail connection can be established with the manufacturerwith the possibility for the manufacturer to feed backinformation on the likely cause of equipment failure.

Well and equipment performance data is normally collected bythe operating company itself, or through assistance from acontractor. The data is then checked for consistency andquality in accordance with the agreed data collectionrequirement. Upon data quality compliance, the data aremerged into a master database, which in turn is fed back to thecontributing member companies on CD-ROMs. A subset ofthe data (equipment failure data) can be viewed by the JIPmember companies in a dedicated Internet browser,WellWatch. The different steps of the data collection, QA anddata feedback cycle is shown in Figure 1.

Database contentsThe Wellmaster database is currently the most comprehensivecompletion equipment database worldwide, with participationfrom 16 major oil companies in Phase III. Key figures on thedatabase scope are as follows:

More than 71000 completion string items represented inequipment database

A total of 1002 equipment failures included for a total of5 different completion equipment categories

A total of 1613 wells with 1921 completions are included,representing a total of some 8000 completion-years ofexperience

The majority of data in the Wellmaster database is from theNorth Sea. Figure 2 illustrates the data distribution by region.In Phase III, a fair amount of data from the Gulf of Mexico hasalso been added, whereas earlier project phases have includedalmost exclusively North Sea data.

The database is dominated by data from oil producers, but asignificant amount of data from water injectors andgas/condensate producers are also included. A breakdown ofwell type vs. well service time is shown in Figure 3.

With respect to completion type, the data are dominated bydata from fixed offshore platforms (79.6 %), but a

considerable proportion also exists for subsea completed wells(11.4 %). The remaining data are from TLP wells (6.1 %) andonshore wells (2.9 %).

2. Case histories (benefits)Heidrun TLPThe first TLP (Tension Leg Platform) on the Norwegiancontinental shelf was installed in Saga Petroleum's Snorrefield. The production risers for the Snorre TLP are fitted withpassive fire protection. The decision to use passive fireprotection on the risers was based on detailed regulationsissued by the Norwegian Petroleum Directorate (NPD) and aseries of risk analyses performed by Saga Petroleum.

In 1992, the NPD issued the new risk analysis regulations3.These regulations state that a risk analysis should beperformed for all major potential risks associated withoffshore field development and operation. The results fromthe analysis shall be measured against risk acceptance criteriawhich have to be pre-defined by the operating oil company. Ifthe risk level as demonstrated by the risk analysis is below thepre-defined acceptance criteria, the results from the riskanalysis may in some cases override the requirements given inmore detailed regulations concerning certain safety systems.

The Statoil Heidrun platform is the 2nd TLP installation onthe Norwegian Continental shelf. For this development,several risk analyses were performed which addressed theneed for passive fire protection of the risers.

SINTEF was requested to do a 3rd party verification of thesestudies, in order to produce input to the final decisionconcerning the issue of fire protection of the Heidrun risers.

The main decision point in these risk analyses was theblowout escalation risk, i.e the risk that a blowout on one ofthe oil production wells would escalate to additional wells -thus jeopardizing the entire Heidrun TLP. The blowoutescalation risk is directly related to the rate of critical failuresof the downhole safety valve (DHSV/SCSSV).

In the 3rd party verification study, a review and update of thestudies with the latest reliability data for SCSSVs wasperformed. This clearly indicated that the blowout escalationrisk for the Heidrun TLP was within the pre-definedacceptable level. This led to an approval from the NPD todevelop the Heidrun field without passive fire protection ofthe TLP production risers.

This led to a cost saving of minimum NOK 720 million (caUSD 81 million) for the Heidrun TLP when compared to theSnorre TLP. Without the availability of updated andrecognized, independent SCSSV reliability data this costsaving would not have been achieved.

SPE 63112 APPLICATION OF A COMPLETION EQUIPMENT RELIABILITY DATABASE IN DECISION MAKING 3

Alternative SCSSV leakage acceptance criteriaA paper4 presented earlier this year summarized the findingsfrom a study which has looked at alternative leakageacceptance criteria for SCSSVs. The basis for the widely usedAPI RP 14B was reviewed and compared with an alternativemethod to define acceptance criteria (leak rate levels). Thisalternative method utilizes principles from risk and reliabilityanalysis to suggest a systems oriented approach for primaryand secondary barriers (the x-mas tree master valve and theSCSSV) in combination - rather than looking at these items onan isolated basis.

Rather than applying the API RP 14B criteria for all welltypes, the paper suggests the use of a matrix withrecommendations on well type specific risk levels andcorresponding acceptance criteria. Compared to todayspractice, this implies a certain relaxation of acceptance criteriawithout compromising the overall safety level. This isachieved through increasing the test frequency whenever asituation arises in which one of the main barriers(PMV/SCSSV) has failed according to the existing API RP 14B criteria.

The direct implication of this is that considerable cost savingscan be achieved during the wells lifetime. The cost savingpotential is greatest for subsea producers, due to the high costof interventions.

The results from the work described in this paper are nowcarried forward and implemented into a new NORSOKstandard (D-009) for risk based acceptance criteria forSCSSVs. This standard will be applicable for the NorwegianContinental Shelf, but can also be applied internationally. Thestandard is expected to be ready by the end of 2000.

SCSSV removal from subsea completions?A hot issue over the last 1-2 years involving extensive use ofcompletion and subsea equipment reliability data in riskanalysis is the issue of SCSSV removal from subseacompletions. Studies have been performed on this issue inBrazil, Gulf of Mexico (through) and in the U.K., with a studyunderway in Australia as this paper is written. In the authorsopininon, there is no general answer to this question. Thisissue has to be addressed on the basis of local/regionalregulations concerning requirements on external protection ofsubsea wellheads and x-mas trees and the risk picture(dropped object risk, trawlboard impact risk and otherpotential external damage factors).

Studies have also been performed where non-conventionalcompletion configurations have been studied, typically onremoval of annulus safety systems from gas lifted wells.

2. Results

The Wellmaster Phase III project extended previous historicaldata provided by SINTEF. The Ekofisk Bravo blowout inNorway in April 1977 paved the way for a collective effort onimprovement of safety levels for Norwegian offshoreinstallations and was the basis for SINTEFs initial reliabilitystudy on SCSSVs which was published in 1983. Since then, anunbroken chain of historical data on performance of bothSCSSVs and other completion equipment data has followed.

Figure 4 illustrates the historical evolution in SCSSVreliability. A significant improvement in SCSSV performancehas resulted, from an initial Mean Time to Failure (MTTF) of14.2 years (1983) to the most recent result of 36.7 years(1999). This represents a tremendous boost in well productionavailability and availability of the SCSSV as a safety barrier.Morever, downhole reliability data has become an importantinstrument in communication with interpretation of auhoritiesrules and regulations in many offshore regions around theworld. The challenge for many operators is the time lag fromdemonstration of performance improvement to revisions ofgovernmental regulations.

A distinct trend in well completions is the increasedpreference towards the use of single rod piston, flapper typetubing retrievable safety valves without equalizing feature.This trend towards design standardization is paying offwhen looking at this purely from a SCSSV reliability and wellintervention standpoint. However, as a result of the reductionin piston area, the control pressure needs to be increased. Thishas some negative effects for subsea completions, with highcontrol umbilical pressures, increased probability of hydraulicleaks in control pods, subsea hydraulic connections and other.

High completion equipment reliability is particularlyimportant for subsea completed wells, particularly in deepwaters. This is illustrated by some examples from the NorthSea, which were reported in the Wellmaster Phase III project:

Well A experienced a failure (leakage in closed position) ofthe TR-SCSSV in June 1995. Upon failure diagnosis of thewell, a tubing to annulus communication due to a leakingGLV was noted. The well was shut down and a subseaworkover followed. Due to problems with rig availability andproduction allocation restraints, the well was off productionuntil October 1996. During the workover, the failed GLV wasreplaced and an insert valve was run inside the failed TR-SCSSV. Total well downtime was 476 days.

Well B also involved a failure of the SCSSV. A critical failure(leakage in closed position) occurred on the TR-SCSSVduring initial completion, in August 1997. The failure wascaused by a coiled tubing bottom hole assembly hanging upwhile pulling out of hole at TR-SCSSV depth, indicatedthrough flapper and hinge pin damage during the subsequent

4 EINAR MOLNES AND GEIR-OVE STRAND SPE 63112

workover. Workover 1 took place during January/February1998. The tubing hanger was found to be stuck in the wellheadand failed to release. Dolomite particles from a kill pill wasfound to be jamming the tubing hanger lock/unlockmechanism. The workover was aborted, and preparations weremade to re-enter the well through Workover 2, where thetubing hanger was to be milled out. Workover 2 wasperformed during April/May 1999, when the tubing hangerwas successfully milled, the tubing pulled and a newcompletion string run. The well was brought back onproduction in May 1999 after a shut-in period of 482 days.

In both cases, the shut-in period was extended due tolimitations in rig availability. Both wells are prolificproducers, causing significant loss of revenues in this period.

3. Conclusions

Reliability databases have been present in the offshoreindustry for some two decades, with the number ofapplications of reliability data in decision making continuallygrowing.

The key to successful reliability databases in the offshoresector lies in populating the databases with data in sufficientquality and quantity. In the current low cost era of theindustry, it is difficult to convey the benefits of thesedatabases to management.

A wider acceptance of the benefits of the results now seems tobe emerging, with current focus on stronger implementation ofthe data collection software throughout the organizations andmore frequent updating of the historical data now high on theagenda of the participating oil companies.

Collection, analysis and feedback of reliability data is aneffective means of communicating performance of equipmentand operations across organizations boundaries. The fact thatreliability data is now being utilized for definition of newstandards and governmental regulations, is another indicationof the need for continuous collection and analysis of reliabilitydata by independent third parties.

ACKNOWLEDGEMENT

The authors wish to thank the participants of the WellmasterPhase III project for permission to publish this paper. Theparticipants were A/S Norske Shell,Amerada Hess Norge A/S, BHP Petroleum Pty. Ltd.,BP Exploration Operating Company Ltd., BG PLC, EnterpriseOil plc, Mobil Exploration Norway Inc., Norsk Agip A/S,Norsk Hydro ASA, Norske Conoco AS,TOTAL Norge A.S,Saga Petroleum ASA, Statoil, Chevron Petroleum TechnologyCompany, Exxon Production Research Company and TexacoGroup Inc.

NOMENCLATURE

GLV Gas lift valveMTTF Mean time to failureMTTW Mean time to workoverNORSOK The competitive standing of the Norwegian

Continental ShelfOREDA Offshore Reliability DataSCSSV Surface Controlled Subsurface Safety ValveTR Tubing retrievableWR Wireline retrievable

REFERENCES

/1/ ISO 14224: Petroleum and natural gas industries Collection of reliability and maintenance data forequipment. Issued by ISO/TC 67/WG 4 N5, July1999.

/2/ Molnes, E. and Strand, G.-O.: Reliability of WellCompletion Equipment Phase III Main Report.SINTEF Petroleum Research Report32.0898.00/04/99 (Confidential). Trondheim,November 1999.

/3/ The Norwegian Petroleum Directorate: Regulationsconcerning implementation and use of risk analysis inthe petroleum activities. First issued 1994.

/4/ Molnes, E. and Strand, G.-O.: Towards risk basedacceptance criteria for downhole safety valves.Paper presented to Petrobras VI Technical Meeting Reliability Engineering, Rio de Janeiro, 28-30 March2000.

SPE 63112 APPLICATION OF A COMPLETION EQUIPMENT RELIABILITY DATABASE IN DECISION MAKING 5

B uffe r D a tabase

W ellW atchH T M L

W eb B row ser

M o dera to r/Q A

O nline W ellW atchD atabase

Users - Oil com panies Users - Manufacturers

E xproS oftW e llm aste r

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C lien tve rs ion 2 .5

W ellm aste rW indow s N T A gent

G enera te au tom aticrep ly and con firm ation

M a nufac tu re r

Fa ilu re report dup lica te Fa ilu re cause com m ent

C om panyD atabase

Figure 1 Wellmaster/WellWatch information flow chart.

Figure 2 Distribution of wells by region.

Distribution Wells by Region

North Sea86.5 %

Other0.1 %

GoM8.1 %

S.E. Asia/Australia2.5 %

Africa2.7 %Adriatic

0.1 %

North Sea Other GoM Adriatic Africa S.E. Asia/Australia

6 EINAR MOLNES AND GEIR-OVE STRAND SPE 63112

C o m p le tio n T yp e vs . S erv ice T im e

01 0 0 02 0 0 03 0 0 04 0 0 05 0 0 06 0 0 07 0 0 0

F ixe d p la t fo rmwe ll

S u b s e ac o m p le te d we ll

T L P c o m p le te dwe ll

O n s h o rec o m p le te d we ll

C o m p le tio n T yp e

Serv

ice

Ti

me

(ye

ars

)

Figure 3 Distribution of well service time by welltype.

14.2 16.4 12.7

20.2 19.55

36.69

05

101520253035404550

SCSSV I(1983)

SCSSV II(1986)

SCSSV III(1989)

SCSSV IV(1992)

Wellmaster II(1996)

Wellmaster III(1999)

MTT

F (ye

ars)

Figure 4 Historical development of TR-SCSSV (flapper valve type) reliability during the period 1983-1999.