managing well integrity on erskine normally … · well integrity experiences 1. tubing condition...
TRANSCRIPT
© 2018 Chevron North Sea Limited
Managing well integrity on Erskine
Normally Unattended Installation
The first HPHT development in the UKCS
Iain Robertson
Erskine Petroleum Engineer
Chevron North Sea Limited
27th June 2018
© 2018 Chevron North Sea Limited
Presentation Overview
• Erskine field development
• Well design
• Well integrity experiences
– Tubing condition and liner deformation
– Scale
– Annulus Management
– Subsurface Safety Valves
– Christmas tree and wellhead
• Closing thoughts
Erskine Normally Unattended Installation - Well Bay
© 2018 Chevron North Sea Limited
Field Overview• Gas condensate field discovered in 1981
• First gas in 1997 via 5 production wells
– Still the same 5 wells producing
• Chevron (50% operator)
Chrysaor (32%)
Serica Energy (18%)
• Tied-back to the Chrysaor operated Lomond
platform via 30km multiphase pipeline
– Condensate exported to the Forties Pipeline
System
– Gas exported to CATS
• High pressure (960 bar) and high temperature
(175oC)
– Currently depleted by ~600 bar
• Water depth 100m
• Field developed using an innovative NUI
– Normal POB of 12
– Maximum of 134 days attended per year
– Minimal facilities design
1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017
Erskine Field Historic Gas Production
Erskine Field Map
2000’E 2001’E 2002’E 2003’E 2004’E 2005’E 2006’E 2007’E
57000’N
57001’N
57002’N
57003’N
57004’N
57005’N
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--4
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2STRE
19Y
W1
W2
W3
W4
W5
84
3RE
7
15
14
Ers
kin
e
Fie
ldP
.057
Ers
kin
e F
ield
P.2
64
Blo
ck
23/2
6b
Machar Field boundary
(above 12000’)
GW
C
N2 km
2000’E 2001’E 2002’E 2003’E 2004’E 2005’E 2006’E 2007’E
57000’N
57001’N
57002’N
57003’N
57004’N
57005’N
-4650
- 4650
-470
0
--4
75
0
-4600
-4600
-4800
-4850
-4900
-4950
-5000
-5050
-5100
-5150
-5200
- 4950
-49
00
- 4900
- 4950
-5000
- 4850
- 4800
- 4550
-4750- 485
0
- 4950
- 5050
- 5150
- 5250
- 5000
- 4950
-5300
-5350
-5400
-5500
-5500
- 5350
- 5600
-5300
2STRE
19Y
W1
W2
W3
W4
W5
84
3RE
7
15
14
Ers
kin
e
Fie
ldP
.057
Ers
kin
e F
ield
P.2
64
Blo
ck
23/2
6b
Machar Field boundary
(above 12000’)
2STRE
19Y
W1
W2
W3
W4
W5
84
3RE
7
15
14
Ers
kin
e
Fie
ldP
.057
Ers
kin
e F
ield
P.2
64
Blo
ck
23/2
6b
Machar Field boundary
(above 12000’)
GW
C
N2 km
2STRE
W1
W2
W3
W4
W5
84
3RE
7
15
14
W1
W2
W3
W4
W5
14
7
48
15
3RE
19Y
2STRE
Beta
Terrace
Alpha
Terrace
Main
Field
Machar Salt Dome
Reservoir and Fluid Properties• Jurassic sandstone
• Heather Tubidite
• Erskine (Puffin)
• Pentland
• CGR 180-210 bbl/scf
• Condensate gravity 40o API
• Column height: 500ft
• Reservoir depth: 15,500ft
• Porosity 20%
• Permeability 80mD
SPE 56899
Erskine Field: Early Operating Experience
Top Erskine Z Structure TVDSS(m)
E&A Wells
Production Wells
Erskine Well Design
• Design Considerations
– High pressure and high temperature
– Flow rates up to 60MMscf/d
– Ability to perform rig-less interventions (i.e. plug back
wells and perforate in upper sands)
– High reliability
• Design Features
– Monobore completion for through tubing plug backs
– PBR instead of production packers
– Corrosion resistant alloys
– Tubing Retrievable Subsurface Safety Valve (TR-SSSV)
with the option for Wireline Retrievable Subsurface
Safety Valves (WR-SSSV) in case of TR-SSSV failure
– Designed for a 20 year life (now at 21 years) with
several years to COP date
• W4 was successfully worked over in 1999 following
failure of the tubing
SPE 30364: HPHT Drilling and Completion Design for the Erskine Field
SPE 67779: Erskine Field HPHT Workover and Tubing Corrosion Failure InvestigationExample Erskine well schematic
5” liner
7” liner
16” casing
12 1/8” x
10 ¾” x
10” casing
20” casing
30” casing
9 5/8” x 8” x 7 5/8”
tie-back
4.5”
tubing
Well Integrity Experiences
1. Tubing condition & liner deformation
• In order to assess the condition of the liner and
tubing, calliper logs are routinely run on all
Erskine wells
• Tubing condition is good throughout
• All wells have experienced some form of liner
deformation
– Shear Deformation
– Axial Buckling
• Following initial deformation, subsequent
surveys show that limited further deformation
has occurred
– Risk of well failure due to liner deformation is
therefore presumed to be low
• Deformation can restrict access to the
perforations putting limits on data-gathering and
well interventions
Example of a typical deformation features in
the 5” liner
Well Integrity Experiences
2. Scale
• Severe scale deposition has occurred on some wells
where we have experienced significant water production
– W5 lost production due to scale in 2005 . A coiled
tubing intervention was required to restore production
• Moderate scale deposition has been observed on all
wells
– Recent impact of scale has been on deposition across
the SSSV which has required wireline milling
operations to mitigate
• Calliper logs have shown scale deposition across the
perforations on several wells
– Scale can restrict access to the perforations
– May be limiting production
• Most common scales are barium sulphate, zinc
sulphide, lead sulphide and calcium carbonate
• No downhole inhibition or scale squeezes have been
performed
• Scale inhibition is used for protection of the platform
pipework
Scale deposition profile above the SSSV pre and post
wireline milling operations
Coiled Tubing on W5 in 2005
Well Integrity Experiences
3. Annulus Management
• Annuli are monitored constantly using real-
time pressure transducers linked to PI
– Alarm and trip levels defined to prevent
exceeding safe limits
– Monitored at Lomond and by Chevron
onshore team
• Periodic bleed-downs of annulus pressure
required to maintain well integrity
– Can require rapid intervention when
Erskine is unattended
– Bleed-down fluids are analysed onshore
as required
• Majority of bleed-offs for the C and D annuli
– A and B annulus bleed downs are very
infrequent
0
2
4
6
8
10
12
14
A B C D
2017 Annulus Bleed Down Counts
W1(P1) W2(P2) W3(E2) W4(KA) W5(E3)
Well Integrity Experience
4. Subsurface Safety Valves• All wells were initially fitted with TR-SSSVs
• Over time some TR-SSSVs have been replaced with
WR-SSSVs
• Two wells have suffered from SSSV control line
failures so have had storm chokes fitted
– Removes the need for a workover
– Storm chokes cannot be tested in-situ
– Requirement for annual changeout
– Inspections after each replacement have found no
significant issues
• Alternatives to storm chokes that don’t require a
workover would be beneficial to the asset
– Could be tested in-situ
– Remove the annual changeout requirement
– Save on the cost of replacement and a workover
Storm choke valve before and after
cleaning
Well Integrity Experiences
5. Christmas Tree and Wellhead
• Tree and wellhead are rated to 15,000psi
• Tree valves and wellhead are subject to
annual testing and inspection (PMR)
• If a pressure test cannot be achieved, either
maintenance is performed or a risk
assessment is done to ensure sufficient
barriers are in place to safely operate the well
• All wells have had a tree change in the past
• The main issue experienced is the wellhead
test-port elastomeric seals failing. This
prevents adequate testing of the metal to
metal seals
– More prevalent when testing cold
– This needs to be monitored as the wellhead
ages
OTC 8742 :HPHT Platform Wellheads &Christmas Trees- Performance Testing to
Installation
Erskine wellhead and Christmas tree
Example Tree Change Photos - 2010
© 2018 Chevron North Sea Limited
Closing Thoughts
• Erskine wells are still operating safely after 21 years and need to keep going to
maximise economic recovery
• The well design has facilitated low cost interventions to maintain well integrity
• Liner deformation has been observed in all wells but does not appear to be
dramatically worsening with time
• Wireline offshore days have typically been used for well integrity related activities
rather than production enhancement opportunities
• Scale management has been reactive. Options are being looked at for proactive
scale management
• Alternatives to storm chokes that don’t require a workover would be beneficial for
the asset
Acknowledgements
• Yusif Zeynalzade (Chevron) and Paul Ness (Chevron) for providing
technical review
• Chrysaor and Serica Energy for kindly agreeing to this presentation