Upload
userscribd2011
View
219
Download
0
Embed Size (px)
Citation preview
8/10/2019 End Eli Gm Oete Ref 030605
1/23
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.
8/10/2019 End Eli Gm Oete Ref 030605
2/23
24.07.2003 2
CZ
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.
8/10/2019 End Eli Gm Oete Ref 030605
3/23
24.07.2003 3
CZ
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.
8/10/2019 End Eli Gm Oete Ref 030605
4/23
24.07.2003 4
CZ
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.
8/10/2019 End Eli Gm Oete Ref 030605
5/23
24.07.2003 5
CZ
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.
8/10/2019 End Eli Gm Oete Ref 030605
6/23
24.07.2003 6
CZ
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.
8/10/2019 End Eli Gm Oete Ref 030605
7/23
24.07.2003 7
CZ
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
8/10/2019 End Eli Gm Oete Ref 030605
8/23
24.07.2003 8
CZ
NPDS PRESENTATION
8/10/2019 End Eli Gm Oete Ref 030605
9/23
24.07.2003 9
CZ
8/10/2019 End Eli Gm Oete Ref 030605
10/23
24.07.2003 10
CZ
NORSKE SHELLS PRESENTATION
8/10/2019 End Eli Gm Oete Ref 030605
11/23
24.07.2003 11
CZ
8/10/2019 End Eli Gm Oete Ref 030605
12/23
24.07.2003 12
CZ
8/10/2019 End Eli Gm Oete Ref 030605
13/23
24.07.2003 13
CZ
BPS PRESENTATION
8/10/2019 End Eli Gm Oete Ref 030605
14/23
24.07.2003 14
CZ
8/10/2019 End Eli Gm Oete Ref 030605
15/23
24.07.2003 15
CZ
8/10/2019 End Eli Gm Oete Ref 030605
16/23
24.07.2003 16
CZ
8/10/2019 End Eli Gm Oete Ref 030605
17/23
24.07.2003 17
CZ
PERTRAS PRESENTATION
8/10/2019 End Eli Gm Oete Ref 030605
18/23
24.07.2003 18
CZ
8/10/2019 End Eli Gm Oete Ref 030605
19/23
24.07.2003 19
CZ
8/10/2019 End Eli Gm Oete Ref 030605
20/23
24.07.2003 20
CZ
NORSK HYDROS PRESENTATION
8/10/2019 End Eli Gm Oete Ref 030605
21/23
24.07.2003 21
CZ
STATOILS PRESENTATION
8/10/2019 End Eli Gm Oete Ref 030605
22/23
24.07.2003 22
CZ
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
3 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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
4 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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)
5 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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.
6 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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
8/10/2019 End Eli Gm Oete Ref 030605
23/23
24.07.2003 23
CZ
7 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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
8 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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.
9 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
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
10 Esso Norge ASAnExxonMobilSubsidiary6-Apr-05
NPDMeetingACCSSVsJune03.ppt
END