NORSOK D-010:
Section 7 Completion
Respondent
WIF / Jan Krokeide
Date
Section
15.09.2012
7
Chapter
number
15.10
Suggested text
Comments
Change bullet i B from "provide a seal in annulus space between the itself and
the wellhead," to "• provide sealing in between the tubing, wellhead and x-mas
tree,"
Submitted before
15.09.2012
7
15.10
Change D to the following: "All seals shall be tested in the direction it is
designed to hold pressure."
A seal cannot be qualified if not tested the correct way.
WIF / Jan Krokeide
15.09.2012
7
15.10
Add a point to F: "2. Accessible seals (land- and platform wells) shall be
Leaks through TH seals is a commonly known industry problem. The status should be known such that repairs and mitigating actions
periodically leak tested, first time within 1 year then at a maximum frequency of can be done avoiding further escalation of leak to the surroundings.
2 years."
Yes
Yes
WIF / Jan Krokeide
15.09.2012
7
15.12
Change A to the following: "This element consists of the wellhead housing and Typing error and clarify that the valve is an annulus valve.
an annulus isolation valve."
Yes
WIF / Jan Krokeide
15.09.2012
7
15.12
Add 5 point to F as follows:
"2. The test duration for the valves shall be minimum 10 min, test duration is
volume and compressibility dependent and shall be hold for a period giving
measurable pressure change for the allowed leak rate
3. Manual valves exposed to injection or production fluids shall be minimum
leak tested every 6 months. For passive annuli the manual valves shall be
minimum tested yearly.
4. Injection valves shall be leak tested at regular intervals as follows:
• monthly, until three consecutive qualified tests have been performed,
thereafter • every three months, until three consecutive qualified tests have been
performed,
thereafter • every six months
For existing fields with good reliability data for the valve type and specific fluid
and rate conditions, 1 monthly and 1 three monthly test is sufficient before
increasing the regular test intervals to every six month
5. If the leak rate cannot be measured directly, indirect measurement by
pressure monitoring of an enclosed volume downstream of the valve shall be
performed.
6. The injection valves shall be periodically function tested including the
emergency shutdown function based on reliability analysis but as a minimum
yearly. It shall be verified acceptable shut down time and that the valve closes
on signal."
Missing requirements for valve testing
Yes
Change C point 5 to the following:
"5. When used in conjunction with annulus injection (gas lift, cuttings injection,
etc.) any low temperature cycling effects need to be taken into consideration
and the valve shall be.:
• surface controlled,
• automatically operated,
• fail-safe closed,"
Same requirements of fail safe etc as for XT and DHSV in this case
WIF / Jan Krokeide
15.09.2012
15.09.2012
7
7
15.12
15.29
Yes
7
15.29
C point 1: Change to: "1. The components (pipe and threads) shall be gas tight Gas tight treads should only be required when exposed to HC
whenever exposed to hydrocarbons during its lifetime. "
Yes
WIF / Jan Krokeide
15.09.2012
7
15.29
C point 4: Change to "For gaslift valves and CIVs to qualify as a well barrier
there shall be a qualification test demonstrating the valves ability to be gas
tight over an operator defined number of cycles. The valve shall be subject to
frequent testing with acceptable results similar to testing of SCSSVs"
Yes
WIF / Jan Krokeide
15.09.2012
7
7
15.29
15.29
Add same requirements to CIV as to GLV.
Add a point to D as follows: "2. The valves shall be tested with both low and
It is not sufficient to only test to METP
high differential pressure in the direction of flow. The low pressure test shall be
maximum 7MPa."
Yes
Change F from "1. Pressure integrity is monitored by independence of the
annulus pressure." to:
"1. Pressure monitoring of annuli, control/ injection lines .
2. Valves (e.g. gas lift valves or chemical injection valves) to be periodically
leak tested according to testing of ASVs and with the same leak acceptance
criteria."
Yes
Need to cover all monitoring methods of the items in the completion string
WIF / Jan Krokeide
15.09.2012
7
15.43
C point 3: Change the bullet "• Grade V1 for design validation," to "• Grade V1 The liner top packer will leak gas if not gas tight when free gas at depth.
for design validation, V0 if free gas at depth"
Yes
WIF / Jan Krokeide
15.09.2012
7
15.43
C: Add a point to the list: "7. For gas lifted wells where liner top packer is
This is an important point to add for gas lifted wells
exposed to gas lift, the liner top packer shall be set at depth with sufficient
formation strength and casing isolation material to prevent possible out of zone
injection. The same requirements as for production packer / tie-back packer
shall apply."
Yes
F. Change to the following: "Monitoring of annulus pressure or none if below
production packer. "
Yes
WIF / Jan Krokeide
15.09.2012
7
15.43
G
100 %
G
100 %
G
100 %
None monitoring is not always relevant. Dependant on setting depth.
changed
added
word added
added
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added
G
15.09.2012
15.09.2012
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Yes
WIF / Jan Krokeide
WIF / Jan Krokeide
G
G
Change B from "Its purpose may be to provide support to the functionality of
Change control line filter subs to control line with seals/connections etc.
the completion, i.e. gas-lift or side pocket mandrels with valves or dummies,
nipple profiles, gauge carriers, control line filter subs, etc." to "Its purpose may
be to provide support to the functionality of the completion, i.e. gas-lift or side
pocket mandrels with valves or dummies, nipple profiles, gauge carriers,
control line with seals/connections, etc. "
Editor Comment
changed
Yes
WIF / Jan Krokeide
WIF / Jan Krokeide
Category
(W, G , Y, R,
B)
Status
100 %
changed
G
100 %
G
100 %
added
added
G
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G
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added
changed and added
G
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G
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added
added
G
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G
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added
WIF / Jan Krokeide
15.09.2012
7
15.7
Change heading of table from "15.7 Table 7 – Production packer " to "15.7
Table 7 – Production packer / tie back packer"
Tie back packer is often also a barrier element that would need the same requirements as for production packer
Yes
WIF / Jan Krokeide
15.09.2012
7
15.7
Rephrase first point in C from "1. It shall as a minimum be tested to V1 class
as per ISO 14310" to "1. It shall as a minimum be tested to V1 class as per
ISO 14310. V0 if free gas at depth"
V1 is not sufficient if free gas is present at depth, then gas will leak through and problems with annulus pressure build up in the
operational phase will occur.
Yes
WIF / Jan Krokeide
WIF / Jan Krokeide
WIF / Jan Krokeide
WIF / Jan Krokeide
[email protected]
15.09.2012
15.09.2012
15.09.2012
15.09.2012
15.09.12 16:39
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7
7
7
7
15.7
15.8
15.9
15.9
7.6.1
Add a point to C: "2. The setting shall be at a depth such that any leak through It is important to add a requirement to the placement/depth of the packer. It is a commonly known problem in the industry that
the casing below the packer, will be contained by the barrier system outside
unfortunately some wells have nor properly isolation outside the packer leading to e.g. out of zone injection etc.
the casing. This means formation integrity and any annulus seal (e.g. Cement)
shall be able to withstand the pressures or temperatures expected throughout
the lifetime of the well"
Yes
Change F to the following:
"1. The valve shall be leak tested at specified regular intervals minimum as
follows:
• monthly, until three consecutive qualified tests have been performed,
thereafter • every three months, until three consecutive qualified tests have been
performed,
thereafter • every six months.
• test duration is volume and compressibility dependent and shall be hold for a
period giving measurable pressure change for the allowed leak rate. Minimum
30 min for HC, and 10 min for water.
2. For existing fields with good reliability data for the valve type and specific
fluid and rate conditions, 1 monthly and 1 three monthly test is sufficient before
increasing the regular test intervals to every six month
2.3. Acceptance of downhole safety valve tests shall meet API RP 14B
requirements being
• 0,42 Sm3/min (25,5 Sm3/hr) (900 scf/hr) for gas,
• 0,4 l/min (6,3 gal/hr) for liquid.
3.4. If the leak rate cannot be measured directly, indirect measurement by
pressure monitoring of an enclosed volume downstream of the valve shall be
performed.
4. The valve shall be periodically function tested including the emergency
shutdown function based on reliability analysis but as a minimum yearly. It shall
be verified acceptable shut down time and that the valve closes on signal. The
shut down time is recorded at bled down hydraulic system."
Yes
Test duration of 30 minutes does not give any meaning for other than HC wells. For water wells 10 minutes is commonly used in the
industry.
Regarding the test frequency, the standard should be differntiated between new wells/fields without reliablility data and new wells with
good field data and good reliability data for the same valve type at the field.
It is very confusing to write in the standard that the test can be attempted 3 times. If the valve fails at the first test this is a safety
critical error and the test should therefore be regarded as failed and count as failed when calculating reliablility. Measures and
attempts to repair the valve should not be written in this context as it confuse the reader to misunderstand when the valve actually is
regarded to have failed.
Need to add requirement of periodic function testing.
100 %
G
100 %
added
Change F to the following:
Same reason as for changes to F in 15.8
"1. The valve shall be leak tested at specified regular intervals as follows:
• test duration shall be minimum 30 min (10 min for water), test duration is
volume and compressibility dependent and shall be hold for a period giving
measurable pressure change for the allowed leak rate
• monthly, until three consecutive qualified tests have been performed,
thereafter • every three months, until three consecutive qualified tests have been
performed,
thereafter • every six months
2. For existing fields with good reliability data for the valve type and specific
fluid and rate conditions, 1 monthly and 1 three monthly test is sufficient before
increasing the regular test intervals to every six month
3. Acceptance of downhole safety valve tests shall meet API RP 4B
requirements being
• 0,42 Sm3/min (25,5 Sm3/hr) (900 scf/hr) for gas,
• 0,4 l/min (6,3 gal/hr) for liquid.
4. If the leak rate can not be measured directly, indirect measurement by
pressure monitoring of an enclosed volume downstream of the valve shall be
performed.
5. The valve shall be periodically function tested including the emergency
shutdown function based on reliability analysis but as a minimum yearly. It shall
be verified acceptable shut down time and that the valve closes on signal. The
shut down time is recorded at bled down hydraulic system."
Yes
Suggest adding the following wording: “All safety critical components […]”
Typically safety critical components are string components from the tubing hanger down to and including the production packer. A
leak in the tail pipe typically would not constitute a safety problem (but it might have operational implications, but this should be
assessed by the operator).
100 %
added
G
Yes
added to heading for table 43
added
G
Add 3 point to C as follows:
These point are covered for SCSSV but not for ASV, but are as valid here.
"6. It shall be
• surface controlled,
• automatically operated,
• hydraulically operated,
• fail-safe closed,
7. It should be placed below the well kick-off point in order to provide well shutin capabilities below a potential collision point.
8. The fail-safe closing function (maximum setting depth) should be calculated
based on the highest density of fluids in the annulus.
All components of the completion string including connections (i.e. tubing,
packers, polished bore receptacle, nipples, mandrels, ASV, valve bodies,
DHSV, plugs, etc.) shall be subject to load case verification”
G
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added
G
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added
G
G
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100 %
Accepted and implemented the wording
"safety critical" and equipment listing
deleted as the operator has to define
safety critical components as part of the
safety case.
WIF / Jan Krokeide
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WIF / Jan Krokeide
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Sveinung Robertson / Statoil
[email protected]
15.09.2012
7
7.6.5
Rephrase "c) Production tree valves master valves – PMV, AMV." to "c)
Production tree master and wing valves."
Why is wing valve removed from the list of beeing part of the emergency shut down system? Wing valve shall be part of the system
according to PSA regulation.
14.09.12 10:08
7
7.7.2
“All platform wells shall have an ASV installed in the A-annulus […] A gas lift
injection valve (a WBE) can be used as an alternative to an ASV in subsea
wells. […]”
Clarification required: Does that mean that an ASV is no longer a requirement for subsea wells, as long as gas lift mandrels with gas
lift valves (check valves) are used?
15.09.2012
7
7.7.5
14.09.12 14:43
7
15.10 B
Function
15.9.2012
7
15.6
14.09.12 12:44
7
7.1
Rephrase "b) B-annulus shall have continuous pressure monitoring with
Cement is not a horizontal barrier and a leak in prod csg at intermed csg depth may occur. This means that the formation at int csg
alarms. For subsea wells the B-annulus shall be designed to withstand the
depth must have sufficient integrity independant of the cement height for prod csg.
thermal pressure build-up. If this is not possible, a pressure management
system shall be implemented. If the production casing is not cemented into the
intermediate casing, the exposed formation shall have a documented ability to
withstand a leaking production casing scenario."
to "b) B-annulus shall have continuous pressure monitoring with alarms. For
subsea wells the B-annulus shall be designed to withstand the thermal
pressure build-up. If this is not possible, a pressure management system shall
be implemented." Rephrase: "e) Production casing / liner cement should be
cemented into the intermediate casing unless it can be documented that the
formation can withstand METP (production casing leak scenario)." to "The
formation at intermediate csg depth shall have a documented ability to
withstand a leaking production casing scenario."
may provide a profile to receive a BPV or plug to be used for nippling up/down The last bullet point is not entirely correct, as many tubing hangers are manufactured without a profile for BPV or plug
the BOP or Xmas tree
Jeg foreslår at tabell 6 i Norsok D010 fjernes og at tabell 28 dekker det som stå i tabell 6. Dette fordi utstyret beskrevet i tabell 6
etter min mening greit kan defineres til høre inn under utstyret i tabell 28 . Ved å bruke kun en tabell (tabell 28) for mekaniske
plugger unngår en forvirring og at en kan bli fristet til å velge den "letteste" tabellen. Jeg har gjennom årene erfart at det er mye
usikkerhet om hvordan innholdet i tabell 6 skal forstås.
This section covers the requirements and guidelines for well integrity whilst
installing the completion string
No
G
100 %
Yes
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No
Rephrased
G
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G
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G
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word added
reworked and combined the to tables
Implemented - thanks
The first sentence is too long and has 5 "and's" in it. The grammar needs to be changed
This activity commences after the well is drilled and logged, The completion
phase ends when the tubing hanger is landed and tested in the subsea
wellhead or when a surface xmas tree is installed
Accepted
G
100 %
G
100 %
Accepted
G
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Agree
The purpose of this section is to describe the establishment of well barriers by
the use of well barrier elements and guidelines to execute this activity
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14.09.12 12:44
7
7.3d
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14.09.12 12:44
7
7.3f
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14.09.12 12:44
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7.6.1
A DHSV shall be installed in the completion string for all wells
For surface wells this should be A and B annulus
Minimum requirements for completion string design shall be established and
documented
Incorporated
All completion, liner and tie-backs strings shall be designed to withstand all
planned and/or expected stresses, including those induced during potential well
control situations. The design process shall be for the full life cycle of the well,
including abandonment. Degradation of materials shall be taken into
consideration. The design basis and design margins shall be documentes
G
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G
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G
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G
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G
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G
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B
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Design faktor krav matcher ikke kap 4.3.5 (Beskrevet oppfor). I tillegg er tri-axialt design for connection ikke relevant i dagens
oljeindustri. Er absolutt mulig, men krever andre kompetanser og andre design tools. (I Statoil kan vi benytte connection performance
envelopes, for moderne connections, men det gir ikke design faktor som svar.)
G
100 %
Reference made to section 4.3.5 and
deleted from this section
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14.09.12 12:44
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7.6.2d
fluid and/or gas data
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14.09.12 13:22
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7.6.2k
(New)
Plug and Abandonment
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14.09.12 13:22
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7.6.3 table
item 4
Dynamic flowing and injection conditions
Water, Gas, WAG and SWAG injection wells are also subject to temperature effects
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14.09.12 13:22
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7.6.3 table
item 6
Bullheading/Pumping
Injection should be added to 7.6.3 table item 4, as stated in the previous comment number 5
Added
Added
Incorporated
Incorporated
In comments section; Well killing, stimulation and fracturing
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Dag Johan Eiane / Statoil
14.09.12 13:22
14.09.12 13:22
15.9.2012
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7
7
7.6.3 table
item 8
comments
section
Stuck sring, shear ratings of pins/rings. Tensile strenghth of all completion
components, including equipment connections
7.6.4
For through tubing plugs, packers and valves, the design pressure shall be a
minimum of 1.1 times the stated MWP/maximum exposed load, whichever, is
the highest. These plugs.................
7.6.4
Added
Deleted as comments from industry
states this to be an operational
requirement and not a design
requirement
Dag Johan Eiane / Statoil
15.9.2012
7
7.6.4
Hva betyr setningen I klar tekst? "As an alternative to the above design factors…………………….."
G
100 %
Deleted
Dag Johan Eiane / Statoil
15.9.2012
7
7.6.4
Siste setningen i 7.6.4 er et operasjonelt krav og ikke et design krav.
G
100 %
Deleted
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14.09.12 13:22
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7.6.5b
G
100 %
Accepted
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14.09.12 13:22
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7.7 Section
The needs to a sub section included for Injection wells (Water, gas, WAG and SWAG)
G
100 %
Updated the disposal well section to
include injection wells
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14.09.12 13:22
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7.7.1
No suggestions, but the paragraph (one long sentence) requires re-writing to make it clearer
G
100 %
Agree and hope the new wording is
better
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14.09.12 13:22
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7.7.2
Dag Johan Eiane / Statoil
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15.9.2012
7
7.7.2
14.09.12 13:22
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7.7.2c
ASV or other fail safe closed devices, if installed
Gas lift is a mothod to increase production whereas the back pressure in the
production tubing is by injecting gas into the A annulus and through the tubing
at a pre-determined depth downhole. The use of gas lift means large volumes
of pressurised hydrocarbon gas in both the surface lines and the A annulus.
Release of these volumes is a substancial topsides hazid to the platform
The gas lift well definition has been
deleted based on your comment
Hvorfor benyttes D-010 til å forklare hva en gass løft brønn er? D-010 er et kravsdok og ikke laerebok.
Gas should only be introduced to casing to tubing annulus, that has gas tight
premium connections that are properly made up and tested
B
100 %
G
100 %
G
100 %
Noted
Updated