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