挪威海德罗公司油气井完整性

Well Integrity within Norsk Hydro

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 K?re 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

AMV AVV ACV

BMV

AWV

XOV SIV SIT

P

MBS

Production

Scale Inhibitor Methanol

Flow -line connector

PCV

PWV SCV

PMV

P

Sliding sleeve

Flow control valves

Retrievabl e 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 Year

Field 1995199619971998

199920002001200220032004BORG 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 S 豏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 豐T 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 %1

4.6 %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. Abdollahi Sintef

Best practice ISO test Wear testing

Dope-free connection

Tommy Langnes

OCTG

Wear testing Geir Ove Haugen

Drill pipe

Diagnosis Packer design Safety factors Best practice Course Database

Barrier test procedure

Hilde B. Haga Completion design

Wear testing Material selection Tore R Andersen Material technology

Diagnosis Course Procedures

Thorvald Jakbsen Prod. technology

Inge M. Carlsen

Sintef

Reference group : Bj ?rn Engedal (leader), Nils Romslo, Geir Slora, Eli Tenold, Bjarne Syrstad, Torbj ?rn ?vreb ?, 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

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 diagnosis

2. Evaluation

3. 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 normal

operation

Compare Acceptance

criteria

Annulus

pressure

limits

Diagnosis

Risk and response

evaluation

Implementation and

follow-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 normal

operation

Compare Annulus

pressure

limits

Diagnosis Well design

Monitoring

Leak location

(P vs. TVD)

and leak rate

estimation tools

provided

Task 2; Risk assessment and response evaluation

Acceptance criteria Risk and response

evaluation Implementation and

follow-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. P A above MOASP

during normal operation)Acceptable only if risk factors can be controlled (e.g, reduce P A 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 criterion OR

Well 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.OR

There 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 OR

Mechanical / 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