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Minutes of meeting

Supervision of activitiesO-CoPNo

24.07.2003 CZ

To: Anna Kristine Oma, Eivind Sande, Gunnar H. Leistad, Brd Christian Jensen, Hildedegrd, participants of the companies

Copy: Anne Vatten, F-Boring, O-CoPNo

From: Claas v. d. Zwaag (CZ)

Date of meeting: 05.06.2003

Place of meeting: NPD/TrollPresent: Anna Kristine Oma, Eivind Sande, Gunnar H. Leistad, Brd Christian Jensen, Hilde

degrd, Claas van der Zwaag, V. Thomas/NShell, S. Skoglund/NShell, K.Owren/Statoil, H. Boge/CoPNo, R. Nilsen/CoPNo, K. Sandve/CoPNo, . Ekeli/CoPNo,

Slensminde/NHydro, K. Harestad/Esso, B. Williams, Esso, A. Huse/Pertra-DPT, J.E.Olvin/BP, A. Hide/BP, J. Bergem/BP

Document no: 2003/1099

EXPERIENCE WITH ANNULAR SAFETY VALVES IN GAS LIFT OPERATIONS

SummaryA large inventory of lift gas under high pressure may amplify the risks and consequences of a blowout from gas lift

wells. Regulations therefore demand that an annulus that is used for lift gas injections shall be equipped with a downhole safety valve, also called annular safety valve (ASV).

The participating companies presented field cases on safety issues related to gas lift well completions. In particular,field experiences concerning ASV were discussed. Operating gas lift wells without such safety valves requires consentfrom the NPD. Exemptions are based on the assessment of operative risks and the evaluation of alternative solutions or

compensating measures by the responsible/operator. The goal is to approach an equally safe or safer situation as withannular safety valves in gas lift wells.

Cases that were discussed at the meeting differed in many aspects and demonstrated the difficulties to set a single safetystandard to annular safety valves in gas lift operations. Such differences are e.g.:

- Subsea vs. platform completions- Type of facility (steel jacket, buoy, GLB, TLP, FPSO or semi-sub)- Purpose of facility (wellhead platform alone or in combination with processing facilities, drilling modules or

accomodation)- Production volumes and phase of production (plateau or tail) as well as remaining reservoir energy in relation

to natural reservoir lift capacity- Annular volumes and pressure conditions.

Major observations and conclusions were:

- 6 out of 7 companies claim that workover operations related to installation or maintanance of ASV contributesubstantially to the total risk in gas lift operations.

- 6 out of 7 companies consider that ASV do not positively contribute to the safety of subsea gas liftcompletions.

- There are a number of measures that successfully are used to reduce risks. These are e.g.: deepset safety valvesbelow the GLV, GLV-qualification as barrier element, different types of safety valves installed at or in thewellhead, stringent monitoring and control routines.

- Regulations should avoid detailed requirements related to ASV. The responsible should be able to demonstratethat safety on the installation is sufficiently recognised. A NORSOK standard or the like could be an adequate

means to make risk assessments related to gas lift operations more systematic.


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Minutes

Agenda:0900-0930 Welcome and Introduction

0930-1215 Presentation of Field Cases (w/ Exemptions)

Draugen, Shell

Ula, BPEkofisk/Eldfisk, ConocoPhillips

Varg, Pertra

1215-1300 Lunch

1230-1330 Presentation of Field CasesGrane, Norsk Hydro

Jotun/Balder, Esso

Heidrun/Veslefrikk, Statoil

1330-1430 Discussion and Summary

The meeting started with a brief introduction into NPDs current organisation.

NPD continued with an orientation on present and past regulations concerning requirements to

annular safety valves in gas lift operations. According to the new HES regulations, the Facilities

Regulations 53 Equipment for completion and controlled wellflow demands down hole safety

valves in the annulus, so called annular safety valves (ASV), if the production annulus is used forgas injection.

Due to a large number of applications for exemptions in the last 2-3 years, the NPD asked whether

regulations were perceived as too detailed in the industry, and, whether an attempt to work outbetter, functional requirements would maintain or even increase the safety level of gas lift wells.

Norske Shell, Draugen

Gas-lift on Draugen producers is performed both in subsea and platform wells.

Subsea wells are completed with deepset safety valves as primary barrier elements. These are

positioned below the gas lift valves (GLV). GLV are not qualified as barrier elements. The gas

inventory in the annulus is considered to present a rather small risk regarding consequences andescalation in case of a major accidents on subsea installations. Workovers on ASV in subsea well

completions, however, contribute substantially to the total risk in gas lift operations. Experiences

with deepset safety valves has been positive so far. NSh referes furthermore to extensive

experiences of the Shell group on 10000 gas lift installations world wide. Operations haveshown that GLV often leak and that deepset valves or ASV may be more reliable barrier elements

than GLV.

Gas lift wells on the Draugen platform were designed with respect to some special features thatdistinguish Draugen from other cases:

- The platform is built on a monohull concrete jacket. All risers are collected in the jacket.Operations require a defined hydrostatic balance in the monohull in order to avoid collapse.

A blowout with gas and oil release into the monohull and a loss in hydrostatic balance mayhave catastrophic consequences.

- Draugen is not equipped with a platform rig. Workovers on ASV would require a self-

contained rig.- Reservoir energy is still high and reservoir blowout is a relevant accident scenario.


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Norske Shell (NSh) runs gas lift wells without ASV after consent by the NPD. Wellheads are

equipped with doubleblock safety valves, so-called gas lift isolation safety valve (GLIS), whiledeepset safety valves are installed below the gas lift valves in subsea wells. The NPD put forward

requirements to install ASV when working over wells, however, so far no well had to be worked

over since production from Draugen started. Also, ASV would have to be placed relatively deep

(650 m) due to technical considerations (cratering). The annular gas inventory would only bereduced from 40 m3injection gas at appr. 200 bar to 16 m3, i.e. the inventory would not be

substantially eliminated.

NSh performed several risk assessment and consequence studies (safety and environmental riskanalysis, HAZOP) before applying for exemptions. An explosion loading study for the well head

area was performed. NSh reports that GLIS valves can take a fair amount of abuse and are build

fairly robust. They would have been installed irrespective of the installation of ASV.

ASV installation and maintanance demands a separate rig. ASV are therefore considered difficult to

maintain and risk analyses indicate that the risk involved in a workover outweighs risks related to

the gas inventory in the annulus. The Shell ALARP related to gas lift on Draugen includes insummary:

- GLIS- Deepset SSCV as qualified and tested as barrier elements in subsea wells, i.e. any ASV if

installed would not have a (reservoir) barrier function.

- Deluge system- Gas detection system.

Discussion:- NORSOK standard sets requirements to ASV in platform wells, however, the standard does

not specify any requirements for subsea valves. This should be reconsidered.- 6 out of seven of the participating oil companies supported a general perception that ASV do

not positively contribute to the safety of subsea completed gas lift wells.

BP, Ula

Ula was originally not designed for gas lift. Today, 7 of 14 wells are oil producers. 3 of theproducers are now completed for gas lift. Flow energy on these wells is low and they would not

produce without gas lift. 2 of the 3 gas lift wells were completed without ASV for low pressure (75

bar) gas lift operations in a campaign in 1992/93. These inject the lift gas at low depth into the

production tubing. One well was completed as a high pressure (180 bar) gas lift well in 2001 withgas injections deeper down in the well. ASV were set at 270 m and after one year of operations, the

ASV has performed troublefree.

Some basic features that affect risk analyses of the Ula field case are:- Platforms are built on steel jackets.- The wellhead/production platform is separated from drilling and living quarters- Gas lift wells are equipped with gas lift valves (GLV) that are qualified and tested as barrier

elements, i.e. any ASV if installed would not have a (reservoir) barrier function.

Gas lift valves (GLV) in Ula wells are qualified and tested as barriers. Tests are carried out every 6

months. Leakage tests of GLV can take considerable time when carried out according to APIprocedure.


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QRA were performed after exchanging information with Shell. Benefits from ASV were considered

to be small. Studies showed that there is a high risk associated with installation and workover ofASV. PLL values were calculated and indicate a PLL-value of 1 per 5 to 90 yrs. Workover

frequency was set to 1 per 25 years. The QRA concluded that there is virtually no increase in risk

level for gas lift wells that are not equipped with ASV. Risk is on the same level as standard

production wells (i.e. with no gas lift). Risk was assessed in terms of PLL-values.

If gas lift is required, all new Ula-wells will be completed with ASV. ASV will be installed in new

wells because there may be a small benefit related to the annular gas inventory. The main benefit of

ASV is in their function as a 3rdbarrier and specifically as a barrier against unintenional flow ofthe lift gas from the annulus.

ConocoPhillips, Ekofisk/EldfiskCoPNo applied at the NPD for exemption from 53, Facilities Regulations, due to malfunctioning

of the existing ASV .

ASV were introduced on Ekofisk in 1996 at the start of the Eko II project. Eldfisk A and B alsohave ASV installed in new well completions. ASV are typically installed without being set a long

time before gas lift operations commence. Of 56 installed ASV, 28 have now been set. CoPNo

measures seal failures on 19 of these. Seal failures were identified as the predominating type of

failure.

GLV are qualified as primary barrier elements. A CoPNo performance measurement programme

indicated 98% reliability of the GLV.

To compensate for problems associated with ASV and at the same time reduce the risks associated

with workovers, over the last 3 years, CoPNo designed and tested Annular Safety Check Valves(ASCV), a flapper type of valve derived from Coiled Tubing applications that is mounted into the

wellhead. Several wellheads (total 6) on EKO X and ELD A have been equipped with ASCV on thelift gas injection side. On the opposite side of the wellhead a service valve is installed and may be

opened for pressure control and bleeding off pressure for well maintenance.

CoPNo presented a comparative risk analysis for 3 casesa) Gas lift with fully operational ASV

b) No ASV/defective ASVc) as case 2 but with ASCV installed in the wellhead.

Some guiding characteristics:

- ASV installed and operational means that the loss of platforms is prevented in case ofcatastrophic hazardous events (collisions, explosions)

- No ASV/ASCV means that hazardous events lead to loss of platform.- Maximum lift gas leakage volumes for alternative a) are appr. 5 m 3at 150 bar and for

alternative b) and c) 80 m3at 150 bar

Risk analysis (so far) is based on blowout frequencies and shows that lower total frequencies areapproached with the solution where ASCV are installed in the wellhead relative to the solution with

fully operational ASV. The higher blowout frequency when ASV are installed is related to a

substantial contribution of well intervention operations to blowout frequency.


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When the maximum lift gas volume in the annulus is considered alone, risk related to leakage is

higher for both cases that have no ASV installed (b and c). The difference in risk is especially large

when calculating with 99.5% ASV reliability. However, when ASV reliability is reduced thedifference gets smaller and at 60% ASV reliability any solution has the same risk level. Are the

ASV less reliable as 60%, as in the current situation, risk levels for well completions without ASV

are less risky. All calculations consider an ASCV-reliability of 98%. This value has been

determined in CoPNos ASCV study.

ASCV-maintenance operations require bleeding off the annulus pressure via the manual valve at the

wellhead. These are planned for every 3 month. The risk contribution of ASCV maintanance

operation has not been included into the above risk calculations.

Installation of ASCV on both sides of the wellhead have been evaluated earlier, however, two

ASCV would prevent annular pressure observations when both ASCV are closed. This is in conflict

with NORSOK requirements. CoPNo is in the process of assessing the risk impact of completingwells only on one side with ASCV.

DiscussionQ: Did CoPNo develop ASCV due to regulatory or safety issues?A: Combination of both.

Q: Should ASCV be installed in all North Sea wells?

A: Doing nothing may also be an option costs and benefits have to be assessed and compared.Comments: Shell/BP wouldnt have used ressources on the issue, however, the positive aspect of

the ASCV as a safety element sheltered in the wellhead and the risk reducing effect become clear.

Further Comments:- Shell/BP have co-operated on gas lift and ASV risk issues since quite a while.

- CoPNo has done work on their own and in co-operation with consultants- Operators observe in general that safety issues related to gas lift wells are complex and

require heavy weighters within risk analysis. The NPD should employ more riskanalysis specialists.

Pertra, VargThe Varg field is developed with an unmanned wellhead platform. The produced oil is pumped to

the Varg FPSO. One of the Varg-producers is artificially lifted by gas lift. Gas lift is necessary due

to high water cuts. There is some reservoir energy left and the well could be produced into a test

separator without gas lift.

Wells were completed in 1999 by Norsk Hydro and were initially not planned to be gas lifted. In

september 2001 GLV were installed into the production tubing. Directed by Norsk Hydro, a gas lift

comparative risk analysis for different options (with and without installation of ASV) wasperformed in summer 2001. This analysis showed that for the remaining field life (expected to be

the end of 2002 at this time), installation of ASV would implicate a higher blowout frequency than

running the gas lift well without ASV. This calculation had been made under consideration of the

following compensating measures:1. Installation of a double block valve at the wellhead2. Frequent tests these valves to verify well integrity.

3. Annular pressure monitoring.


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In march 2002, the field was purchased by Pertra. On application, the exemption to run gas lift

without ASV was extended by the NPD to the end of 2003.

Hydro/Grane-Brage

All producers on Grane are planned with gas lift because of the viscous reservoir fluid. ASV will be

installed at appr. 250 m depth. This results in a process gas volume above the ASV of 7 8 m3

anda total annulus volume of 30 40 m3. Injection pressure is between 150 and 160 bar. Two GLV will

be installed in each gas lift well. ASV are part of the primary barrier envelop, while GLV will not

be qualified as barrier elements.

With reference to current gas lift operations on the Brage field, NH reported that experiences with

ASV have been good so far. In a few cases leaks were observed. In these cases, circulating Diesel

helped to re-establish functionality. For Grane, in case of ASV-failure, Hydro currently works on a

procedure where gas lift is going to be shut down before circulating Diesel or initiating any majorworkover operation.

Esso/Balder, Jotun-RinghorneOf 18 oil producers on Jotun/Ringhorne all are gas lifted. Balder comprises 12 oil producers of

which also all are gas lifted. ASV/packer single are installed just below the tubing SCSSV on

platform wells. In subsea wells ASV/packer are installed just below a dual hanger.

Esso has not observed any problems with the ASV so far. One incident was registered related to acontrol line failure.

ASV are installed and tested as primary barrier elements. In case of an ASV failure Esso would

investigate the option to qualify the GLV as barrierelements.

Esso confirms Shells experience that leakages over GLVs are quite common.

Statoil/Heidrun-Veslefrikk

On Veslefrikk, 7 of 11 producers are completed as gas lift wells. On Heidrun producers are

completed for gas lift (dual completions), yet gas lift is discontinuous. Failure during installations

has prevented Statoil to run continuous gas lift on 2-3 wells. These wells need workover beforecommencing with continuous gas lift.

ASV are installed (and set) on all gas lift wells. GLV are not defined as barrier elements. Statoil has

seen problems with the reliability of GLV and the qualification of GLV as barrier elements.

Discussions

NS Regulations should avoid detailed requirements concerning annular safety valves. Theresponsible should be able to demonstrate that safety on the installation is sufficiently recognised.

EM The discussion is mainly about old vs. new wells. Costs related to installation and

maintanance of ASV in old wells will be too high to defend benefits.EM It was worthwhile to get information on other companies cases and information on what

background applications for exemptions are put foreward.

EM Observe that workovers are easier to defend economically when well production is high.


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CoPNo It would be very useful to understand the different techniques to perform risk analyses.

Available risk analyses on ASV-issues should be compared and differences should be evaluated. It

would also be useful to collect data for leakage statsitics both for ASV and GLV.

Statoil In general good experience on Heidrun and Veslefrikk. Gas lift is shut in in case of ASV-

failure. ASV are barrier elements. GLV are not part of the barrier envelops.

BP GLV vs. ASV failure rates should be assessed in a risk level project.

All companies Any joint initiative to change (NORSOK) standards or define best practices would

stand stronger if the NPD participates actively.

CZ, 24.07.03

Revision CZ, 22.01.04Last revision CZ, 07.04.05


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NPDS PRESENTATION


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NORSKE SHELLS PRESENTATION


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BPS PRESENTATION


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PERTRAS PRESENTATION


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NORSK HYDROS PRESENTATION


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STATOILS PRESENTATION


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ESSO NORGES PRESENTATION

6-Apr-05

NPDMeetingACCSSVsJune03.ppt Esso Norge ASAnExxonMobilSubsidiary

NPD Meeting

5 June, 2003

Annulus Safety Valves on

Gas Lifted Wells

Esso Norge

2 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05

NPDMeetingACCSSVsJune03.ppt

Esso NorgeProducing Fields Overview

22

16

9

35

211 34

30

25

16

7

7

15

35 36

31 32

26 27

17 18 19

8 9 10 11 12

2 0

OIL FIELDSGAS FIELDSOIL AND GAS FIELDSCONDENSATE FIELDSESSO LICENSESOTHER LICENSES

0 50 km

Stavanger

Bergen

JOTUN

BALDER

RINGHORNE

Bal0338



Balder /Ringhorne SubseaDevelopment

Drilling:

- Phase I: 1997 - 1999

- Phase II: 2001

SubseaWells- 12 Oil Producers (All Gas Lifted)

- 3 Water Injectors

- 1 Gas Injector

- 1 Water Source

Production to Floating Production Unit(FPU)

Bal4729U

Site D

Site C

9 km

Site B

Site A

RINGHORNEPLATFORM

BALDERFPU

Oil Producers

Water Injectors

Gas Injectors

OP

WI

GI

Existing Balder Subsea Wells

New Subsea Wells

1 2 " O i l l i n e

1 0 " R i c h G a s l i n e

6 " G a s l i f t l i n e

F i b e r o p t i c c a b l e

1 2 " O i l l i n e



Jotunand Ringhorne Platform Developments

Drilling:

- Jotun Phase I: 1999 - 2001

- Jotun Phase II: 2002 -2003

- Ringhorne: 2002 -2005

Platform Wells

- 18 Oil Producers (All Gas Lifted)

- 12 Additional Oil Producers Planned

- 1 Water Injector

- 2 Water Disposal

Production to Floating Production,

Storage and Offloading Units.

FPSO

S HUT T L E

T ANKE R

W E L L HE AD

P L AT F O RM

(not par t of deve lopment project)



Production Characteristics- Gas Lift

Production Characteristics- Gas Lift

- Gas Lift used for initial Well Kickoff and

for Production Lift.

- Gas Lift typically used during all phases

of well life to supplement natural flow

well capacity.



Typical Platform Oil Producer Completions

Typical Platform Oil Producers (Gas Lifted)

- Wire Wrapped Screen Horizontal Completions

- 5 1/2 tubing with hydraulic set permanent packer.

- Tubing Safety Valve- Annulus Safety Valve / Packer Single Gas Lift Valve

- Single Gas Lift Valve installed with initial completion


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Typical SubseaOil Producer Completions

30"csg @ 223.82m MD (Crossoverto 32" @ 174.63m MD)

10 / " x 9 / " crossover @ 617.03m MD3

458

13 / "csg @ 1123.65m MD / 1017.45m TVD / 47.9438

Side Pocket Mandrel forGas Lift Valve

Side Pocket Gauge Mandrel (SPGM)Pressure and Temperature Gauge @ 2440.94m MD / 1534.87m TVD / 70

Top 9 / " 13Cr @ 2329.69m MD / 1496.49m TVD / 70.7658

10 / "x 9 /"csg@ 3270m MD/1757.71m TVD / 85.7358

Final angl e @ TD 89.8

8" hole to TD@ 3791m MD /1751.84m TVD

PBR @ 2460.07m MD /1541.36mTVD/ 70.11

Production Packer@ 2472.38m MD/ 1545.55m TVD / 70.18

Quantum Packer@ 2538.37m MD/ 1568.04m TVD / 69.86

RKB: 23mWater depth: 124.6m

Seabed at 147.6m

ASCSSV

PSCSSV

OCRE FBIV@ 2496.13m MD / 1553.61m TVD / 70.11

34

Top screens @ 3273.65m MD /1757.94m TVD / 86 .06

Washdownshoe @ 3757.01m MD / 1751.74m TVD / 89.9

Typical SubseaOil Producers (Gas Lifted)

- Wire Wrapped Screen Horizontal Completions

- 5 1/2 tubing with hydraulic set permanent

packer.

- Annulus Safety Valve / Packer(below Dual BoreTubing hanger)

- Tubing Safety Valve

- Single Gas Lift Valve installed with initial

completion



Safety Valve Characteristics

Safety Valve Depth

- Production SCSSV

- Driven primarily by Oil Wax Temperature

- Annulus SCSSV

- Platform Wells: Set immediately below Production SCSSV (allows retrieval of Prod.

SCSSV and provide adequate work string weight for annulus packer release).

- Subsea Wells: Set below annulus bore of dual bore tubing hanger

Annulus Safety Valve Type- Platform Wells: Integral Hydraulic-Set Annulus Packer / Safety Valve. Flapper type,

spring to close.

- Subsea Wells: Tubing Retrievable Flapper type. Spring to close.



Annulus Safety Valve Experience

Annulus Safety Valve Experience

- 15 Subsea Wells and 18 Platform Well Completions.

- Up to ca. 4 years production)

- Annulus Safety Valve Failures

- No safety valve bore leak failures to date

- One hydraulic control line leak on initial installation (platform well)

- Other Operating Characteristics

- Extra costs associated with Annulus SCSSV / Packer on wellworkovers.- Extra completion costs associated with annulus safety valve installation

- Production shut-in for annulus safety valve testing



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