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NORSOK D-010
Well integrity in drilling and well operations
Rev. no.4 (June 2013)
What is really new?
Presented at WIF Workshop, Sandnes, 4.6.13
Terje Løkke-Sørensen
Well Engineering Manager
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Milestones
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Comments – round 1 (24.08.11)
Kick-off meeting (26.10.11)
Comments – round 2 (15.11.11)
Mini-hearing EGD/DMF (15.8.12)
EGD meeting (12.12.12.)
Industry Hearing (20.12.2012)
Receive comments (15.2.13)
Submit section draft for QA (12.4.13)
All sections completed (14.5.13)
Compiled draft submitted (27.5.13)
Approved by EGD (27.5.13)
Approved by Standard Norge (30.5.13)
Issue on webb (June 13)
Reflection: Why should it take almost 2 years to revise a standard?
15.11.2011
15.8.12 (DMF,WIF, PAF only)
20.12.12 (Industry hearing)
Total No. 0f comments
Comments received
1
4
0
5
1
8
0
9
38
7
147
192
325
487
Comments
1. Scope
2. Normative & Informative Ref.
3. Definitions and Abbreviations
4. General Principles
5. Drilling Activities
6. Testing Activities
7. Completion Activities
8. Production Activities
9. ST, Susp. & Aban. Activities
10. Wireline Operations
11. Coiled Tubing Operations
12. Snubbing Operations
13. Under Balanced D&C Ops.
14. Pumping Operations
Annex A
112 50
20.12.12
43
28
373
444
16
3
99
118
11
45
237
293
12
25
143
180
40
26
256
322
11
2
84
97
4
0
30
34
5
0
26
31
3
2
60
65
3
0
37
40
4
0
0
4
1. Correct english language
304 200 1817 2321
Com pany
No.
Statoil
441
BP
Shell
BG
COP
PSA
TENAS
Esso
Total
Marathon
Maersk
Petrobras
PGNIG
SLB
367
125
118
102
89
71
68
58
53
43
43
43
39
Lundin
Woodside
AGR
Other (<20)
Sum
31
26
20
80
1817
Reflection: Why does people always
wait till the last minute ?
Estimated total work hours
DONE
Estimate of work hrs per. 30.05.2013
Activity
Project Leader
Editor / EGD / PSA meetings
Section review
Special topic meetings
Initial comments
PIF comments
PAF comments
Mini-hearing (DMF)
Hearing (20.12.12)
Units
16
32
305
3
3
200
1817
hrs/unit
50
16
1
50
50
1
1
Sub-total (hrs)
925
903
800
512
305
150
150
200
1817
TOTAL EST.
5762
+/- 6000 hrs
Reflection: How much time has those who provided the comments spent ?
Reflection: Was it worth it?
Macondo
Norsk Olje & Gass issued a
report with specific
recommendations of what
should be revised in D-010
-> these were tracked
separately and published in the
industry hearing
Main changes
•
Rev.3 normative references has
become informative references
•
WBS are demoted to EXAMPLES only
•
Common WBE requirements moved
to EACs
•
9 new EACs
•
Harmonized with :
– D-001 Drilling Facilities
– D-002 Well Intervention Equipment
– D-007 Well Testing
•
Recommendations from Norsk Olje
og Gass’ Macondo report is included
Potential for increased cost
•
Kill with (1) relief well -> more
casing strings?
•
2 barriers to prevent escape of
gaslift gas -> ASV in subsea well?
•
Logging of critical cement,
tagging & drilling of cement plugs
-> more time?
•
Formation integrity -> deeper
plugs?
•
Injection rate pressure < cap rock
fracture pressure -> reduced
injection rates?
4. General
+
How to make WBS
+
Inflow testing
+
Formation testing and acceptance
+
1+(1) relief well(s), cont. plan & well
capping eq.
+
Well design pressure, design principles
&factors
+
Structural integrity
+
Personnel training
+
WI management system
-
Removed: Well program content,
reporting of well control incident to PSA
5. Drilling activities
+
Casing hanger lock-down capabilities
+
Risk analysis, procedures and training to
centralize pipe prior to closing shear rams
+
The surface casing shall be installed before
drilling into an abnormal pressured zone.
+
Well control action procedures and drills
expanded with new scenarios.
+
Relief well & PA should be addressed in
casing design
+
Conductor design
+
Potential for shallow gas well if no relevant
offset well exists

2 casing float valves – autofill OK no sources
of inflow exposed.
-
Model for minimum separation between
wellbores replaced with generic requirement
Annex A is updated.
BOP testing frequency
unchanged!
6. Well testing activities
+
Able to close two sets of BOP rams on
slick joint (sub sea wells)
+
Evacuated test string load case
+
UB annulus fluid wells; Inflow test values
should include a safety margin
+
SST able to cut wire / CT
+
UB annulus fluid wells; Use of retrievable
packer OK - pressure test packer from
below
-
Removed «HPHT Well testing» section
-
Well Test string equipment -> D-007
-
Surface flow lines /connections -> D-007
7. Completion activities
+
XT, DHSV & packer in all wells with HC / flow pot.
+
Monitoring of production bore, A&B annulus all
wells. Pressure gauge on all accessible annuli.
+
2 more WC action procedures (sand screens,
anchoring failure) and 2 more WC drills (kick drill
RIH completion and emergency disconnect)
+
All gas lift wells shall have two barriers to
prevent release of the A-annulus gas volume
+
All platform wells shall have a ASV
+
ASV can be replaced by GLV
+
CAL IV connection for tubing exposed to gas
+
Injected media to be contained within the
targeted formation zone (reservoir) without risk
of out of zone injection. Requirements to logging
and packer location.
X
8. Production activities
+
All wells to have an updated WBS
+
Wells shall be well integrity categorized as
per GL 117
+
Handover of well documentation
+
How to react to anomalies -> evaluate,
risk assess, MOC
+
Casing & tubing annuli pressure operating
range
+
Safety critical valve failure rates exceeding
2% /12 month period -> root cause
analysis -> actions to reduce the failure
rate.
9. Abandonment activities
+
Simplify by use of examples to support
text
+
Re-defined Suspension to only include
wells under construction, Temporary
Abandonment,- with monitoring (indefinite) and without monitoring (max. 3
years)
+
Examples on placement of plugs/casing
cement (permanent P&A)
+
Relevant EAC tables have been edited
where necessary
+
Decision support for section milling and
placement of cement behind casing
+
Cement plug verification – tag or drill
+
XMT removal requirements added
10. Wireline operations
+
Risk analysis focus - two additional
sections with discussion on reducing
probability and consequences of
compromised WBE
+
Riserless Light WI:
– New section summarising minimum
vertical bore elements in well control
stack
– New WBS example
– New EACs (x3 following Statoil structure)
+
Toolstring deployment:
– New section outlining some alternative
deployment options
– New WBS example for bar deployment
13. MPD/UBD operations
+
Added Managed Pressure Drilling (MPD)
for platforms – does not exclude subsea
operations.
+
Introduced well control action matrices
for MPD and UBD.
+
Introduced ” Additional Common WBE
Criteria” in EAC tables: 2 (Casing), 4
(Drilling BOP), 5 (Wellhead), 22 (Casing
Cement), and 26 (High Pressure Riser)
+
New WBS: MPD
+
Table 53: UBD/MPD choke system
+
Table 54: Statically Underbalanced Fluid
column
+
RCD shall be qualified as per API 16RCD
The other sections
11. Coiled tubing operations
12. Snubbing operations
14. Pumping operations
-> only some minor changes
15. Well Barrier Elements EAC
+
Table 50 – In-situ formation
+
Table 51 – Creeping formation
+
Table 52 – UBD/MPD choke system
+
Table 53 – Statically underbalanced fluid
column
+
Table 54 – Material plug
+
Table 55 – Casing bonding material
+
Table 56 – Riserless Light Well
Intervention – Well Control Package (WCP)
+
Table 57 - Riserless Light Well Intervention
– Lower Lubricator Section (LLS)
+
Table 58 – Riserless Light Well
Intervention – Upper Lubricator Section
(ULS)
15.12 Casing Cement
Verification method
The cement length shall be verified by
one of the following:
1.
Bonding logs: Fit for purpose,
azimuthal /segmented data,
verified by qualified personnel
2.
100 % displacement efficiency .
Actual displacement
pressure/volumes vs. simulations
Losses, -> loss zone to be above
planned TOC (ref. similar loss
case(s) -> sufficient length
verified by logging.)
3.
Losses: PIT/FIT or LOT is OK only
for drilling the next hole section.
Acceptance criteria
Actual cement length shall be:
• above potential source of inflow/
reservoir
• 50 m MD verified by displacement
calculations or 30 m MD when verified
by bonding logs. Formation integrity
shall exceed the maximum expected
pressure at base of interval.
• 2 x 30m MD verified by bonding logs
when the same casing cement will be a
part of the primary and secondary well
barrier.
• Formation integrity shall exceed the
maximum expected pressure at the
base of each interval.
• Injection pressure exceeding formation
integrity at cap rock: Cemented from
injection point to 30 m MD above top
reservoir verified by bonding logs.
24. Cement plug
Verification:
Open hole
Cased hole
In surface
casing
100 m MD, min. 50 m 50 m MD if set 50 m MD if set
MD above source of
on a
on a
inflow/leakage point. In mechanical/
mechanical
transition from open
cement plug
plug,
hole to casing should as foundation, otherwise 100
be min. 50 m MD
otherwise 100
m MD.
above and below
m MD
casing shoe.

Cased hole plugs tested either in the direction
of flow or from above.

Shoe track: bleed back volume = calculated
volume; pressure tested + supported by
overbalanced fluid or inflow tested.

Check surface samples + cure at downhole
temp.& pressure.

Installation verified through evaluation of job
execution

Plug in open hole: Tag (no pressure test)

Plug in cased hole: Tag + pressure test to 70 bar
above LOT below casing/ potential leak path, or
35 bar for surface casing plugs. Exemption: If set
on a pressure tested foundation, no pressure test is
not required -> verify by tagging.

If one continuous cement plug (same cement
operation) is a common WBE, it shall be verified
by drilling out until hard cement is confirmed.
A standard is worth nothing
unless it is referred to!
Knut Heiren, Standard Norge, 2004