Transcript Document

Well Integrity within Norsk Hydro
INTERNAL
Objective
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Develop a consistent procedure for
management of annular leaks
Risk based approach
Routines for early detection and how to
handle the leaks
Procedure made in collaboration between
NH, Exprosoft and Kåre Kopren(PTG)
Key items in the procedure:
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Include detection, diagnosis, assessment and responses to well annular leaks
No increase in installation risk (QRA modelling)
Specific risk reduction measures
Variations in risk level (subsea vs. topside, gas vs. oil, etc.)
Applicable to all well types operated by Norsk Hydro
In compliance with regulations and standards
INTERNAL • Date: 2005-01-13 • Page: 2
Principles
SIT
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Overview of well data and
limitations shall follow the well
throughout the lifetime
All leaks shall trigger an internal
deviation (synergi) – verification in
B&B
Well data shall be updated when a
leak is detected
Checkout of integrity of next
casing
Test program to identify leak
above or below BSV, surface
pressure after stabilizing of
pressure, leak rate
Update of well risk level, based on
Wellmaster database
Update of operational procedures
SIV
AWV
SCV
XOV
ACV
P
PMV
PWV PCV
BMV
WOCS
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Flow - line connector
MBSAVV AMV
P
Methanol
Scale Inhibitor
Production
To The Cutting's Disposal System
DHSV
Screen with ECP and
Pressure gauge
Retrievable
Clean out valve
production
packer
Gas cap gas lift screen and gas lift valve
Side mounted guns
Retrievabl
e isolation
packer
Sliding sleeve
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radioactive tracer
Flow control valves
Status procedure for management of well
annular leaks
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Procedure is finished
Remains:
 Implementation
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Training of offshore personnel to detect leakages + diagnostic work
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A pilot course has been held in april.
Standard course package will be developed based on the experience
from the pilot course
All personell involved in detection and diagnostic work offshore and
onshore will be invited
INTERNAL • Date: 2005-01-13 • Page: 4
Historical Norsk Hydro downhole annulus well
integrity (WI) issues by field
Figure shows “Cumulative #Annulus WI Issues / Cumulative #Completions” by Year
Field
BORG
BRAGE
FRAM VEST
GRANE
NJORD
OSEBERG B
OSEBERG C
OSEBERG SØR
OSEBERG VEST
OSEBERG ØST
SNORRE
SNORRE B
TOGP
TORDIS
TWOP
VARG
VIGDIS
VISUND
Total
1995
1996
1997
0.0 %
0.0 %
7.4 %
2.9 %
0.0 %
2.6 %
0.0 %
0.0 %
2.3 %
0.0 %
0.0 %
0.0 %
0.0 %
1.6 %
0.0 %
0.0 % 14.3 % 14.3 %
0.0 % 0.0 % 0.0 %
0.0 %
0.7 %
1.1 %
0.0 %
0.0 %
2.5 %
1998
1999
2000
2001
2002
0.0 % 0.0 % 0.0 % 0.0 %
9.7 % 17.6 % 60.4 % 57.9 % 54.7 %
0.0 %
0.0 %
0.0 % 16.7 % 12.5 % 35.3 % 44.4 %
2.0 % 1.9 % 1.8 % 6.6 % 8.1 %
3.0 % 6.1 % 6.1 % 5.4 % 5.0 %
0.0 % 0.0 % 9.1 % 14.3 %
0.0 % 0.0 % 0.0 % 0.0 % 0.0 %
75.0 % 27.3 % 20.0 % 21.1 %
1.5 % 2.6 % 3.5 % 7.5 % 8.1 %
0.0 % 0.0 %
0.0 % 0.0 % 0.0 % 0.0 % 0.0 %
12.5 % 11.1 % 11.1 % 10.0 % 10.0 %
0.0 % 4.2 % 8.0 % 7.7 % 39.3 %
0.0 % 0.0 % 0.0 % 0.0 % 0.0 %
0.0 % 0.0 % 0.0 % 0.0 % 0.0 %
0.0 % 0.0 % 0.0 % 0.0 % 10.0 %
3.0 % 6.3 % 12.4 % 14.6 % 16.7 %
2003
0.0 %
60.0 %
0.0 %
0.0 %
47.4 %
7.5 %
5.0 %
11.1 %
0.0 %
25.0 %
8.1 %
0.0 %
0.0 %
10.0 %
39.3 %
0.0 %
0.0 %
10.0 %
16.9 %
2004
0.0 %
59.1 %
0.0 %
12.5 %
47.4 %
7.4 %
5.0 %
10.5 %
0.0 %
25.0 %
8.1 %
0.0 %
0.0 %
10.0 %
37.9 %
0.0 %
0.0 %
10.0 %
17.0 %
20.0 %
15.0 %
10.0 %
5.0 %
0.0 %
1995
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1996
1997
1998
1999
2000
2001
2002
2003
2004
Note: Based on Norsk Hydro WellMaster phase V data (Snorre and Visund currently
Statoil), last major database update April 2004
INTERNAL • Date: 2005-01-13 • Page: 5
Task Force : Well leaks - Root Cause Analysis
Inge M. Carlsen
Sintef
J. Abdollahi
Sintef
Tommy Langnes
OCTG
Geir Ove Haugen
Drill pipe
Best practice
Wear testing
ISO test
Wear testing
Dope-free connection
Hilde B. Haga
Completion design
Tore R Andersen
Material technology
Diagnosis
Wear testing
Packer design
Material selection
Safety factors
Best practice
Course
Database
Barrier test procedure
Thorvald Jakbsen
Prod. technology
Diagnosis
Course
Procedures
Reference group : Bjørn Engedal (leader), Nils Romslo, Geir Slora, Eli Tenold, Bjarne Syrstad, Torbjørn Øvrebø, Siamos Anastasios
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Ongoing work: Well Integrity Management
System (WIMS)
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New database to be developed until 2007
JIP managed by Exprosoft with Hydro, Statoil and Total as
participants.
A development based on the procedure for management of well
annular leaks
Purpose:
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A uniform and structured approach for handling of well integrity during
the lifetime of a well.
All information available through one system
A clear indication of the well barrier status at all times
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Well Integrity Management System (WIMS)
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WellMaster software used as a basis – additional applications to be
developed
Important functionalities:
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Visualising the well barriers and well barrier elements (WBE) through
use of barrier diagrams and barrier sketches
Identify the functions and and requirements that the well and each
WBE should fulfil
Present the status/condition of each WBE (leak, erosion, etc.)
Keep record of performed tests and results of tests
Keep record of diagnosis results when deviations are identified
Keep record of changes in well integrity and resulting corrective actions
Overview of well risk status
Structured / uniform approach to analyze and evaluate risk
INTERNAL • Date: 2005-01-13 • Page: 8
Risk based procedure for management of well
annular leaks
INTERNAL
Rationale for risk based approach
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Reflect variations in actual well risk level
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Subsea, topside
Gas, oil, water
Etc.
In principle no tubing and casing leaks accepted by the PSA
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”to be on the safe side” – leak(s) will affect the operational risk in
a negative way
However;
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Regulations and NORSOK D-010 open for risk assessment
Departure normally granted by submission of supporting risk
analysis results
Must incorporate principle of ”risk reduction” – risk should not be
significantly higher as a result of the deviation
INTERNAL • Date: 2005-01-13 • Page: 10
Procedure outline
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Procedure split in three main tasks
(guidelines):
1. Detection and diagnosis
2. Evaluation
3. Implementation and follow-up
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Well normal
operation
Annulus
pressure
limits
Compare
Diagnosis
Main results
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Acceptance
Extensive diagnosis part
criteria
Risk assessment method
– Specific risk acceptance criteria
– Extensive use of quantitative risk
analysis (fault tree analysis with
WellMaster data as input)
– Specific risk reduction measures
Documentation of process
INTERNAL • Date: 2005-01-13 • Page: 11
Risk and response
evaluation
Implementation and
follow-up
Task 1; Detection and diagnosis
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Collection of basic well data (preparatory)
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When is it needed to assess if there is a leak?
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Establish Max operational A-annulus pressure
(MOASP) = default bleed off alarm limit
Establish pressure domain for initiation of
diagnosis activities
Well design
Monitoring
Annulus
pressure
limits
Well normal
operation
Compare
“External factors” diagnosis
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Well schematic, P- tests/FIT/LOT, annulus
capabilities (as well barrier), annular volumes,
fluid densities, etc.
Abnormal pressure readings may not be
attributed to downhole failure/degradation
Diagnosis
“Internal factors” diagnosis”
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The potential leak rate to the wellhead
surroundings (if blowout through leak path)
Amount of hydrocarbon influx to the annulus
Leak location (depth and relative to well barriers)
Leak failure cause (deterioration/escalation
potential)
Leak directions
INTERNAL • Date: 2005-01-13 • Page: 12
Leak location
(P vs. TVD)
and leak rate
estimation tools
provided
Task 2;
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Risk assessment and response
evaluation
Risk assessment stepwise covers several risk factors
A risk status code (RSC) is assigned to the well in Acceptance
each step
criteria
Most severe RSC determines the RSC for the well
The well RSC determines a set of actions/risk reducing
measures to be implemented - Each risk factor have specific
risk factor acceptance criteria
Risk and response
evaluation
Implementation and
follow-up
Risk factor acceptance criteria basis:
 No risk increase on installation level (as modelled in QRA)
 Quantitative analysis performed for a representative ”library” of well types in
order to measure relative increase in leakage risk and effect of risk reducing
measures
 Rule based/deterministic acceptance criteria (based on industry practice)
– Minimum two well barriers
– No leak to surroundings
– Allowable hydrocarbon (HC) storage in annuli
– Risk of escalation/further detoriation
– Change in well kill opportunity
INTERNAL • Date: 2005-01-13 • Page: 13
Task 2; Well risk status code overview
RSC
Well RSC description
Well risk acceptance
A
No downhole leak
Acceptable
B
Degraded well.
Small increase in risk (none or only related
to HC in annuli)
Acceptable.
Risk can be controlled
C
Degraded well.
High risk increase (e.g. PA above MOASP
during normal operation)
Acceptable only if risk factors can
be controlled (e.g, reduce PA to
below MOASP during normal
operation)
D
Dual barrier philosophy not fulfilled / well
barriers severely degraded / leak to
surroundings
Not acceptable
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RA step 1; Risk factor = Look at well barrier
leak rate consequences
Criteria
RSC
Well barrier leak rate lower than acceptance criterion (not
considered a failed barrier)
B
Leak (any size) to a volume not enveloped by qualified well
barriers
D
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Leak rate acceptance criteria based on leak sizes reflected in
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QRA’s on installation level
API 14B leak rate criteria (SCSSV)
Norsk Hydro risk matrix
Different leak rate acceptance criteria for
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Non-natural flowing or Non-hydrocarbon flowing wells vs.
Hydrocarbon flowing wells
INTERNAL • Date: 2005-01-13 • Page: 15
RA step 2; Risk factor = Relative change in
blowout probability – example
Well barrier leak rates greater than acceptance
criterion (RAC Item no. 5)
Interm.
Csg.
Barrier
Conventional No
platform well
Yes
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T/A leak
below
SCSSV
T/A leak
above
SCSSV
A/B leak
T/A leak above
SCSSV AND
A/B leak
D
C
D
D
D
C
C
C
Risk status codes based on calculated blowout probability and risk
reduction potential assigned to
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Surface and subsea wells
Conventional wells (applies to production and injection wells) and gas lift
wells
Informative calculations performed for multipurpose well, and gas lift well
alternatives with combinations of deep set SCSSV, no SCASSV, annulus tail
pipe SCSSV.
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RA step 3; Risk factor = Look at well release
risk (HC storage - single failure scenario)
Criteria
The hydrocarbon storage mass in the well annuli is, or may
become, greater than the acceptance criterion
OR
Well annuli fluids are highly toxic (platform well)
Otherwise
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RSC
C
B
Hydrocarbon storage criteria relates to:
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For surface wells the quantity of hydrocarbons stored in the well
annuli should not be greater than the typical mass of lift gas in the Aannulus above the SCASSV in a gas lift well OR alternatively the
max recommended volume stored in other vessels on surface
For subsea wells the release quantity criterion is based on distance
to permanent surface installations (rising gas plume) and
environmental acceptance criteria
INTERNAL • Date: 2005-01-13 • Page: 17
RA step 4; Risk factor = Look at leakage cause
(well functionality- degradation)
Criteria
Material corrosion or erosion is the (most likely) leak cause.
There is, or is a potential for, exposure of equipment to
H2S/CO2 levels that are outside design/NACE specifications.
OR
There is crossflow (unintended flow) in the well
Otherwise
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RSC
D
C
B
Further escalation that cannot be controlled should not be
accepted
If further escalation/degradation of the well can be controlled by
given risk reducing measures this can be accepted
INTERNAL • Date: 2005-01-13 • Page: 18
RA step 5; Risk factor = Look at mechanical/
pressure loads (well functionality – loads/single
failure scenario)
Criteria
The maximum potential A-annulus pressure - PA (MTP / Aannulus injection pressure) is greater than MOASP
OR
Mechanical / Pressure loads causing burst/fracture/collapse is
the (likely) leak cause
Otherwise
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B
Maximum Operational A-annulus Surface Pressure (MOASP) is the
limiting wellhead pressure that the A-annulus is deemed safe to be
operated under for an extended period of time (years), e.g., for well
production.
–
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RSC
C
MOASP = Max known P-integrity of next outer functional annulus (from Ptests, LOT, FIT, recognised field formation fracture gradient data)
Checklist for MTP vs. MOASP provided
If A-annulus pressure can be controlled <= MOASP this can be accepted
INTERNAL • Date: 2005-01-13 • Page: 19
RA step 6; Risk factor = Look at well
kill/recoverability (well functionality – well kill
/single failure scenario)
Criteria
An additional single well barrier leak situation may affect the
ability to efficiently kill the well with mud.
Otherwise
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RSC
C
B
If well kill procedures/preparations can be revised and be equally
effective as the base case (well with no failure) this can be
accepted
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Response actions
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The resulting Well RSC determines a set of mandatory (M) and alternative
(S) remedial actions/risk reducing measures to be implemented
Remedial actions for each RSC based on
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Norsk Hydro and industry best practice
The risk assessment (step 1 through 6)
RSC
A
B
C
D
INTERNAL • Date: 2005-01-13 • Page: 21
Response (illustrative example only) A B C D
Revise alarm settings
M M M M
Increased monitoring
M M
Increased well barrier testing
M S
Make plans for well kill
M M
Immediate intervention to restore two
M
well barrier envelopes
Summary
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Applicable to the well types Norsk Hydro operates
In compliance with regulations and standards for the upstream
sector of the oil industry
Guidelines and worksheets included for detection, diagnosis, and
risk assessment and response to well barrier leaks
Support tools and formulas for diagnosis included
Modular system. Easy to update risk factor acceptance criteria,
include additional risk factors, revise risk reduction measures, etc.
Documentation of well “history”
”Library” of relative well leak probabilities - The well leak probability
for a wide variety of well types and leak locations are modelled for
future reference
INTERNAL • Date: 2005-01-13 • Page: 22
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Questions?
INTERNAL • Date: 2005-01-13 • Page: 23