minutes of meeting - petroleum safety authority … konvertert/health, safety...minutes of meeting...

Minutes of meeting

Supervision of activities O-CoPNo

24.07.2003 CZ

To: Anna Kristine Oma, Eivind Sande, Gunnar H. Leistad, Bård Christian Jensen, Hilde Ødegård, 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/Troll Present: Anna Kristine Oma, Eivind Sande, Gunnar H. Leistad, Bård Christian Jensen, Hilde

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

Summary A 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 down hole 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 consent from 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 with annular 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 safety standard 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 contribute substantially 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 lift completions.

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

- Regulations should avoid detailed requirements related to ASV. The responsible should be able to demonstrate that 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, BP Ekofisk/Eldfisk, ConocoPhillips Varg, Pertra

1215-1300 Lunch 1230-1330 Presentation of Field Cases

Grane, Norsk Hydro Jotun/Balder, Esso Heidrun/Veslefrikk, Statoil

1330-1430 Discussion and Summary The meeting started with a brief introduction into NPD’s 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 for gas 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 out better, 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 and escalation 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 have shown 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 that distinguish 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 may have 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)”, while deepset 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 be reduced from 40 m3 injection 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 risk analysis, 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 in summary:

- 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 the producers 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 with gas 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 API procedure.

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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 of ASV. 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 “3rd barrier” and specifically as a barrier against unintenional flow of the lift gas from the annulus. ConocoPhillips, Ekofisk/Eldfisk CoPNo 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 also have 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 the lift 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 cases

a) Gas lift with fully operational ASV b) No ASV/defective ASV c) 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 of catastrophic 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 m3 at 150 bar and for

alternative b) and c) 80 m3 at 150 bar Risk analysis (so far) is based on blowout frequencies and shows that lower total frequencies are approached 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 the difference 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 CoPNo’s 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 completing wells only on one side with ASCV. Discussion Q: 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 wouldn’t 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 “risk analysis” specialists.

Pertra, Varg The 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) was performed 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 wellhead 2. 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 and a 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 major workover operation. Esso/Balder, Jotun-Ringhorne Of 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 a control 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 Shell’s 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 before commencing 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. The responsible 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, 22.01.04 Last revision CZ, 07.04.05

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NPD’S PRESENTATION

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NORSKE SHELL’S PRESENTATION

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BP’S PRESENTATION

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PERTRA’S PRESENTATION

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NORSK HYDRO’S PRESENTATION

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STATOIL’S PRESENTATION

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ESSO NORGE’S PRESENTATION

6-Apr-05

NPDMeetingACCSSVsJune03.ppt Esso Norge ASAn ExxonMobilSubsidiary

NPD Meeting 5 June, 2003

Annulus Safety Valves on Gas Lifted Wells

Esso Norge

2 Esso Norge ASAn ExxonMobilSubsidiary6-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

BALDERRINGHORNE

Bal0338



Balder / Ringhorne SubseaDevelopment

• Drilling: - Phase I: 1997 - 1999- Phase II: 2001

• Subsea Wells- 12 Oil Producers (All Gas Lifted)- 3 Water Injectors- 1 Gas Injector- 1 Water Source

• Production to Floating Production Unit (FPU)

Bal 4729U

Site D

Site C

9 km

Site B

Site A

RINGHORNEPLATFORM

BALDERFPU

Oil ProducersWater InjectorsGas Injectors

OPWIGI

Existing Balder Subsea Wells

New Subsea Wells

1 2 " O i l l i n e1 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



Jotun and 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 H U T T L ET A N K E R

W E L L H E A DP L A T F O R M

(not pa r t o f deve lopment p ro jec t )



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 Subsea Oil Producer Completions

30" csg @ 223.82m MD (Crossover to 32" @ 174.63m MD)

10 / " x 9 / " crossover @ 617.03m MD34 58

13 / "csg @ 1123.65m MD / 1017.45m TVD / 47.94°38

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 / 70.76°58

10 / " x 9 / "csg @ 3270m MD/1757.71m TVD / 85.73°58Final angle @ TD 89.8°

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

PBR @ 2460.07m MD /1541.36m TVD / 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 Subsea Oil Producers (Gas Lifted)- Wire Wrapped Screen Horizontal Completions- 5 1/2” tubing with hydraulic set permanent packer.

- Annulus Safety Valve / Packer (below Dual Bore Tubing 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 well workovers.- Extra completion costs associated with annulus safety valve installation- Production shut-in for annulus safety valve testing



END

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