Well Integrity Management in

Karachaganak Field

DRILLING ROUNDTABLE

Introduction to Well Integrity Management

Why do we are doing it?

• Set up Well Integrity workflow based on industry best practices

(international and parent companies standards, electronic data base,

etc.)

• Accurate and proper well data storage and management

• Quick identification of anomalies and root causes investigation

• Risk evaluation and remediation solutions

• Regulatory documents and procedures development

• Fulfil Regulatory expectations

It’s all about managing the risk

3

Well Integrity Management ( The hidden Dangers)

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Well Integrity Categorization and Failure Management

• Will not require any immediate repairs

• Will require repair on opportunity basis

• Repairs and /or mitigations will be required before the well can be put into normal operation

• For operational stock of wells, it means immediate shut-in, no production until repairs performed.

Carrying out a risk assessment to identify a key threats posed to a well and

recognizing consequences associated with these threats to be addresses

during Well categorization exercise

A annulus Management

• A annulus pressure management requires constant monitoring and

analysis, identification of causes of an A annulus pressure, risk

assessment, A annuli maintenance and remedial works to be

performed on a scheduled sequence.

Diagnostic & Identification of A annulus Pressures

• Diagnostic activities are conducted to meet the following objectives:

o To determine the A annulus integrity and to classify the well stock into 2

groups:

Group 1 - wells with A annulus integrity

Group 2 - wells with A annulus integrity failure

o To identify the cause of A annulus pressure in the wells of Group 2

• Diagnostics activities shall be carried out in all the wells with A

annulus pressure

• Moreover in the event of change of A annulus pressure value or A

annulus fluid composition and also after work over and well

stimulation activities extra investigations shall be performed

• Routine Monitoring

• Special investigations

A Annulus Failure History – Production Well

• A Annulus leak was identified in 2006

• Investigation determined that the leak was below SSSV

• Well was killed and suspended as LTS

• WO has been performed in 2013

X-Mas Tree corrosion on Water Disposal Wells

Multi Finger Caliper (MFC) Water Disposal Wells

A Annulus Failure History Water Disposal Wells

• Well drilled and completed in May 2007

• Water disposal started in January 2009

• A annulus failure was identified in October 2009

• Leak point 2.4 m below TH

• WO was performed May 2010

• Failure cause - packer fluid pH was low due to contamination with acid

ICP Management

• The possible causes of ICP: casing/packer/tubing

leaks, poor cement bond, thermal effect and

wellhead seal failure

• Acceptable Risk Criteria for ICP wells were set up

in ‘Guidelines for Risk Analysis and Prevention of

Hazard Situations at ICP Wells’ that was agreed

with the Ministry for Emergency Situations (MES) of

RoK

• Reporting ICP status on a Quarterly basis

• Annual ICP Management Presentation in Uralsk or

Astana

AA

BC

Causes of Inter Casing Pressures( ICP)

• Leak in tubing or Sealing Elements

o When the pressure integrity of the production tubing or the sealing element is lost,

the primary annulus is exposed to the reservoir pressure, usually resulting in an

increase in the pressure.

o This condition may arise due to poor tubing design, poor packer and seal design,

or erosion/corrosion of the tubing and/or sealing elements.

o In general, however, both the tubing and casing are designed for this load

condition.

o Proper design ensures that the casing can withstand the likely loads imposed due

to a leak

• Failure of Casing

o In some cases, the casing itself may fail, due to corrosion, wear, or thermal

cycling.

• Failure of cement

o The cement column may fail during the service life of the well, thus exposing the

annulus to the pore pressure at the shoe of the shallower casing

ICP Diagnostics

• Continuous monitoring of entire well stock

• Inflow testing and sampling analysis

• Data recorders

• Casing logging

• Pressure bleed-off and build-up analysis

• Wellhead testing and maintenance

ICP Remediation Methods

• Remedial operations during WO

• Wellhead seals remediation

• Production annuli sealing

• Injection of heavy brine

• Controlled annuli fluid bleed-offs

WELL 201 Final situation at rig release

Csg 12 ¾” shoe at 1001m

Production casing configuration

from USIT log August 2006

C.P. 16 ¾” at 104 m

Csg 9 5/8" shoe at 3625 m

Top of Reservoir at 3852m

OB

J 1

AN

D 2

OB

J.3

#

Top of Obj 3 at 4562m

Sa

lt In

terv

al

Top of salt zone at 2819m

Filip

ov

sk

y

7" Casing DV collar at 3495m

Csg 7" shoe at 3859 m

PBTD at 5203m

Bottom of salt at 3657m

Casing

sizeWeight From To

inches lbs/ft m m

7" 35 0 154.2

7" 32 154.2 734.4

7" 35 734.4 768.4

7" 32 768.4 893.7

7" 29 893.7 904.8

7" 32 904.8 916.3

7" 29 916.3 2824.8

7" 32 2824.8 2836.1

7" 29 2836.1 3687.3

7" 35 3687.3 3778.5

Well 201

production casing configuration

Open Hole 8" ½ to 5300 m

Contaminated

Cement bond

ContaminatedContaminatedContaminatedContaminatedContaminatedContaminated

ContaminatedContaminated

Contaminated

C.R. set at 3790m

Top 7" Casing window

window 3580 m

Mu

d w

eig

ht

= 1

.40

S.G

.

Remark: From CBL good bond from 3725 m to 3775 m

3775

C

e

m

e

n

t

b

o

n

d

g

o

o

d

C

e

m

e

n

t

b

o

n

d

N

O

g

o

o

d

3725

cement plug

from 3668 m

to 3790 m

Programmed Bottom 7"

Casing window window at

3610 m

3454 m

3668 m

Kill string 4" ½ New Vam

at 1003 m

cement plug

from 3454 m

to 3668 m

Set with 150

Bars of

pressure

Mill out production

casing and

cementing

ICP elimination by WO

15

ICP DIAGNOSTIC AND REMEDIATION EQUIPMENT

Digital Wellhead pressure recorder

Mobile pump unit

Gravitational displacement unit

Gas flowmeter

Injection well Xmas Tree valve grease issue

Tubing Hanger (UMS) seal failure Injection Well

Tubing Hanger (UMS) seal failure Injection Well

Tubing Hanger seal repair Injection Wells

• On April 21st, 2013 KIOS crew

replaced the UMS accordingly

with Breda procedures.

• Flange connection and UMS

was pressure tested at 550 bar

x 30 min successfully.

• On April 23rd Xmas Tree was

nipple up, the Nitrogen pressure

test of Xmas Tree and inflow

test TH UMS against BPV c/w

Test Prong @ 550 bar x 30 min

was positive.

• UMS material was upgraded to

625 by Breda

• UMS inflow test is performed on

monthly basis on all production

wells

WH valve replacement campaign Shut Down 2016

WH replacement during WO

• Good Practice is to replace

old style WH during WO to

more modern type WH

Mechanical wear (Wellhead Misalignment)

Casing evaluation during WO

• Casing integrity logging is standard procedure during WO

• CBL/VDL, USIT, IBC and etc.

IBC logging tool (Schlumberger)

Tubing Inspections during WO

A Good Practice to inspect tubing condition during WO

The cuts from three tubing depths are performed:

below SSSV,

mid tubing depth,

above packer

Visual Inspection

Wall thickness measurement

Inspection of WH test ports

• Test ports to check for

pressures in the wellheads

• Should be of the “vented

Type” to prevent locking in of

pressures

26

Wellhead Seal Remediation

Corrosion Management

• Corrosion of structural or pressure-containing components of the well

can lead to a loss of well integrity.

• A well is generally exposed to two distinct corrosion processes:

o Internal corrosion that originates from reservoir effluents, injection effluents,

drilling mud, or completion brines;

o External corrosion (e.g. sour gas ingress into production annulus, SRB, surface

corrosion of outer casing)

• Both internal and external corrosion lead to structural integrity

problems and a potential loss of containment if not timely mitigated

• KPO Dynamic Corrosion Inhibitor Program was introduced in 2008 to

ensure that the production well stock tubing was adequately

protected from internal corrosion.

• Well log surveys of tubing strings are useful to determine the location

and severity of any corrosion.

• Multi Finger Calliper (MFC) surveys are carried out every 12 months on Well with

WC above 1%

MFC on the horizontal section of Production Well

MFC 3D results Production Well

Well Completion Metallurgy Optimization

Based on the results of a recent study the

strategy of upgrading the following

components of future well completion in

higher water production risk areas is

currently being investigated.

The following components of well

completion are recommended to be

upgraded:

• 4 ½” Lower completion tubing –

currently T-95.1;

• Swelling packers – currently T-95.1

(Shown in red on the schematic)

Tubing Corrosion Production Wells

Tubing Corrosion Report from PIA

Casing integrity assurance during sidetrack operations

Casing Protectors

Casing Wear Protectors

Wellhead Restoration Of Old Exploratory Wells

Before

After

Well XX