INTERNAL Well Integrity within Norsk Hydro. INTERNAL Date: 2005-01-13 Page: 2 Objective Develop a consistent procedure for management of annular leaks

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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


Questions?

Documents

INTERNAL Well Integrity within Norsk Hydro. INTERNAL Date: 2005-01-13 Page: 2 Objective Develop a consistent procedure for management of annular leaks