INTERNAL
Well Integrity within Norsk Hydro
INTERNAL • Date: 2005-01-13 • Page: 2
Objective
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: 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
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Principles
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
WOCS
To The Cutting's Disposal System
AMVAVV
ACV
BMV
AWV XOV
SIVSIT
PMBS
Production
Scale Inhibitor
Methanol
Flow - line connector
PCVPWV
SCV
PMV P
Sliding sleeve Flow control valves
Retrievable isolation packer
Side mounted guns
Gas cap gas lift screen and gas lift valve
Pressure gauge
DHSV
Retrievable production packer
Clean out valve
Screen with ECP and radioactive tracer
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Status procedure for management of well annular leaks
Procedure is finished
Remains: Implementation
Training of offshore personnel to detect leakages + diagnostic work 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
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Historical Norsk Hydro downhole annulus well integrity (WI) issues by field
Note: Based on Norsk Hydro WellMaster phase V data (Snorre and Visund currently Statoil), last major database update April 2004
Figure shows “Cumulative #Annulus WI Issues / Cumulative #Completions” by YearField 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004BORG 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 %BRAGE 0.0 % 0.0 % 7.4 % 9.7 % 17.6 % 60.4 % 57.9 % 54.7 % 60.0 % 59.1 %FRAM VEST 0.0 % 0.0 % 0.0 %GRANE 0.0 % 0.0 % 12.5 %NJORD 0.0 % 0.0 % 16.7 % 12.5 % 35.3 % 44.4 % 47.4 % 47.4 %OSEBERG B 2.9 % 2.6 % 2.3 % 2.0 % 1.9 % 1.8 % 6.6 % 8.1 % 7.5 % 7.4 %OSEBERG C 0.0 % 0.0 % 0.0 % 3.0 % 6.1 % 6.1 % 5.4 % 5.0 % 5.0 % 5.0 %OSEBERG SØR 0.0 % 0.0 % 9.1 % 14.3 % 11.1 % 10.5 %OSEBERG VEST 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 %OSEBERG ØST 75.0 % 27.3 % 20.0 % 21.1 % 25.0 % 25.0 %SNORRE 0.0 % 0.0 % 1.6 % 1.5 % 2.6 % 3.5 % 7.5 % 8.1 % 8.1 % 8.1 %SNORRE B 0.0 % 0.0 % 0.0 % 0.0 %TOGP 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 %TORDIS 0.0 % 14.3 % 14.3 % 12.5 % 11.1 % 11.1 % 10.0 % 10.0 % 10.0 % 10.0 %TWOP 0.0 % 0.0 % 0.0 % 0.0 % 4.2 % 8.0 % 7.7 % 39.3 % 39.3 % 37.9 %VARG 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 %VIGDIS 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 0.0 %VISUND 0.0 % 0.0 % 0.0 % 0.0 % 0.0 % 10.0 % 10.0 % 10.0 %Total 0.7 % 1.1 % 2.5 % 3.0 % 6.3 % 12.4 % 14.6 % 16.7 % 16.9 % 17.0 %
0.0 %5.0 %
10.0 %15.0 %20.0 %
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004
INTERNAL • Date: 2005-01-13 • Page: 6
Task Force : Well leaks - Root Cause Analysis
J . A b do lla h iS in te f
B e s t p ra c ticeIS O te stW e ar tes tingD o pe -free con n ec tion
T o m m y L a ng n esO C T G
W e ar tes ting
G e ir O ve H au g enD rill p ip e
D ia g n o s isP a cke r de s ignS a fe ty fac to rsB e s t p ra c ticeC o u rseD a tab a seB a rrie r te st p ro ce d u re
H ild e B . H a gaC o m p le tio n de s ign
W e ar tes tingM a te ria l se le c tion
T o re R A n de rsenM a teria l te ch no lo gy
D ia g n o s isC o u rseP ro ced u res
T h o rva ld Ja kb senP ro d . tech n o lo gy
In g e M . Ca rlsenS in te f
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)
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: 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)
WellMaster software used as a basis – additional applications to be developed
Important functionalities: 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
Risk based procedure for management of well annular leaks
INTERNAL • Date: 2005-01-13 • Page: 10
Rationale for risk based approach
Reflect variations in actual well risk level Subsea, topside Gas, oil, water Etc.
In principle no tubing and casing leaks accepted by the PSA ”to be on the safe side” – leak(s) will affect the operational risk in
a negative way
However; 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
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Procedure outline
Procedure split in three main tasks (guidelines):
1. Detection and diagnosis2. Evaluation3. Implementation and follow-up
Main results Extensive diagnosis part 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
Well normaloperation
Compare
Acceptancecriteria
Annuluspressure
limits
Diagnosis
Risk and responseevaluation
Implementation andfollow-up
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Task 1; Detection and diagnosis Collection of basic well data (preparatory)
Well schematic, P- tests/FIT/LOT, annulus capabilities (as well barrier), annular volumes, fluid densities, etc.
When is it needed to assess if there is a leak? Establish Max operational A-annulus pressure
(MOASP) = default bleed off alarm limit Establish pressure domain for initiation of
diagnosis activities
“External factors” diagnosis Abnormal pressure readings may not be
attributed to downhole failure/degradation “Internal factors” diagnosis”
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
Well normaloperation
CompareAnnuluspressure
limits
Diagnosis
Well designMonitoring
Leak location (P vs. TVD)
and leak rate estimation
tools provided
INTERNAL • Date: 2005-01-13 • Page: 13
Task 2; Risk assessment and response evaluation
Acceptancecriteria
Risk and responseevaluation
Implementation andfollow-up
Risk assessment stepwise covers several risk factors A risk status code (RSC) is assigned to the well in
each step 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 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
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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
Leak rate acceptance criteria based on leak sizes reflected in QRA’s on installation level API 14B leak rate criteria (SCSSV) Norsk Hydro risk matrix
Different leak rate acceptance criteria for Non-natural flowing or Non-hydrocarbon flowing wells vs.
Hydrocarbon flowing wells
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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RA step 2; Risk factor = Relative change in blowout probability – example
Risk status codes based on calculated blowout probability and risk reduction potential assigned to
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.
Interm. Csg. Barrier
Well barrier leak rates greater than acceptance criterion (RAC Item no. 5)
T/A leak below SCSSV
T/A leak above SCSSV
A/B leak T/A leak above SCSSV AND A/B leak
Conventional platform well
No D C D D
Yes D C C C
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RA step 3; Risk factor = Look at well release risk (HC storage - single failure scenario)
Hydrocarbon storage criteria relates to: 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 A-annulus 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
Criteria RSC
The hydrocarbon storage mass in the well annuli is, or may become, greater than the acceptance criterionORWell annuli fluids are highly toxic (platform well)
C
Otherwise B
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RA step 4; Risk factor = Look at leakage cause (well functionality- degradation)
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
Criteria RSC
Material corrosion or erosion is the (most likely) leak cause. D
There is, or is a potential for, exposure of equipment to H2S/CO2 levels that are outside design/NACE specifications.ORThere is crossflow (unintended flow) in the well
C
Otherwise B
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RA step 5; Risk factor = Look at mechanical/ pressure loads (well functionality – loads/single failure scenario)
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.
– MOASP = Max known P-integrity of next outer functional annulus (from P-tests, 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
Criteria RSC
The maximum potential A-annulus pressure - PA (MTP / A-annulus injection pressure) is greater than MOASP ORMechanical / Pressure loads causing burst/fracture/collapse is the (likely) leak cause
C
Otherwise B
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RA step 6; Risk factor = Look at well kill/recoverability (well functionality – well kill /single failure scenario)
If well kill procedures/preparations can be revised and be equally effective as the base case (well with no failure) this can be accepted
Criteria RSC
An additional single well barrier leak situation may affect the ability to efficiently kill the well with mud.
C
Otherwise B
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Response actions
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 Norsk Hydro and industry best practice The risk assessment (step 1 through 6)
RSCABCD
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 well barrier envelopes M
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Summary
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
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Questions?