Droshky #3ST2 Through Tubing Intervention

Droshky #3ST2 Through Tubing Intervention
Graeme Miller
Presentation Outline
Project Overview
Well Summary
Intervention Objectives
Intervention
Summary of Operations
Conclusions / Lessons Learned
2
Area Map
GC65
Bullwinkle
GC110
GC113
Angus
Rocky
GC155
GC158
Manatee
Brutus
GC199
Noble Lorien
GC200
GC201
Eagle
Troika
GC243
GC244
D hk
Droshky
Nexen Aspen
3
Drilling Program
 Droshky Discovery 2Q 2007
 Cumulative 9 total penetrations
through the reservoir section
 Exploration – 3
 Appraisal – 3
 Development – 3
 Development program
 Utilized the previously drilled
exploration and appraisal wells
plus 2 new wellbores
 #2ST3 – new sidetrack of the
exploration
l
wellll
 #3ST2 – tie-back of existing
appraisal well
y
 #4 & #5 – newly-drilled
wellbores
4
Conceptual Reservoir Connectivity Model
4
2ST2
2ST3
TVDSS
FEET
150
TVDSS
GR_1
RDEEP_WS_1
0
0.2 OHMM 200
V/V
FEET
150
RT_1
GR_WS_1
0.2 OHMM 200
0
V/V
TVDSS
FEET
150
TVDSS
GR_1
RDEEP_WS_3
0.2 OHMM 200
PERFORATION
V/V
3ST2
PERFORATION
GR_WS_1
0
5
2ST1
PERFORATION
PERFORATION
N
0
V/V
GR_WS_1
RT_1
FEET
150
0
0.2 OHMM 200
V/V
TVDSS
FEET
TVDSS
GR_1
RDEEP_WS_1
150
0
0 2 OHMM 200
0.2
V/V
FEET
150
RT_1
0.2 OHMM 200
S
SB
K
18900
18900
19000
19000
19000
19100
K1A
Lo
b
e
19200
K6 water
B
ou
nd
a
K5
19200
19300
M
L
M
K7
19400
19400
19500
19500
L2B
19600
O
O
L2A
19700
19800
19800
20000
20100
OUw
M1A
OUA
OUB
L2A
L2B
19900
SB
20000
20100
SB
Q
P
Q
19800
19800
19900
19900
K1B
e
Bo
19400
un
da
ry
19500
19600
L2A
19700
20200
20200
20200
OUB
20500
20600
Q4
Q4w
20600
20700
20700
20700
20700
20700
20800
20800
20800
20800
Q2
20800
21100
2007-2009
Pressure Depletion
L2A/L2B: 65 psi
M1A: 55 psi
20900
20900
21000
21000
Q2w
Q1
Q2
20900
Q3
SB
M
20300
Salt
P2
SB
Droshky Well Plan
SB
Development
Proposed
)"
Drill Center
Drilled
Lorien
Lorien water
21000
SB
21100
21200
21200
21300
21300
21300
21400
21400
21400
21500
21500
SB = Sequence Boundary
SB
20300
21100
21200
20000
20200
20500
Lorien
M Stray Sands
20100
20600
SB
SB
20100
20500
L
19900
20100
20600
L4
19800
ry
20100
20600
21000
ou
nd
a
M1A
20500
SB
eB
20000
20400
20500
Lo
b
19700
M1A
20400
SB
SB
19600
19900
20300
20400
19500
SB
SB
20000
K
19400
K1 water
K1 water
19800
L2w
20000
19300
19300
ob
19600
19700
SB
19200
19200
20400
20400
20900
Lorien
L1
19100
K1A
20300
P1
P
K1A
19500
19700
OUB
20300
20300
19400
19000
SB
M1A
20200
20200
19600
19100
19300
19400
SB
19000
19100
19200
K519500
water
K6 water
19000
K1A
K4 L
19300
K5 water
19600
19700
19900
19200
ry
19300
L
K1A
19100
18900
18900
18900
SB
19100
K
18900
21600
5
#3ST2 Completion Schematic
6
#3ST2 Problems
 Annulus bled off to platform prior to startup.
Production Packer (Possibly Leaking)
 After +/- 7 hrs annulus pressure recorded
at tree suddenly increased.
 Diagnostics indicate cause was a packer
leak.
 Well remained shut in during workover
planning.
Upper Zone is Potential
Pressure Source
Intelligent Well System
Isolation Assembly Packer
`
Sand Control Packer
K1 Sand Perforations
Sand Control Packer
L4 Sand Perforations
 Wells 2,
2 4 and 5 brought online July 2010
Sump Packer
9-7/8" Casing @ 21,,005' RKB
TD @ 21,048' RKB'
7
#3ST2 Solution
 Well #2ST3 in communication w/ 3ST2 in K1.
 K1 Sand could be produced from well #2ST3 only.
 Intervention / workover would only be the lower
L4 sand.
sand
 Workover evaluated at higher risk and cost.
 Decision for through tubing intervention to close
the AFIV-C in the isolation assembly.
 Contingency for straddling the Upper ICV to
provide tubing integrity.
8
#3ST2 Intervention Objectives
 Conduct a safe incident free
operation maintaining required
barriers.
 Successfully interface the Helix
Intervention Riser System (IRS) with
the Droshkyy horizontal production
p
tree.
 Provide access through the upper
completion to the AFIV-C
AFIV-C.
 Shift the AFIV-C closed.
 Straddle the upper
pp ICV.
 Pressure test annulus to confirm
integrity.
 Produce well from the lower L4 Sand.
9
Droshky Tree
10
Tree – Helix IRS Interface
11
IRS Stinger Assembly
12
#3ST2 Intervention Operational Summary
 Ran and tested the IRS on 7-5/8” by 2-3/8” dual riser, disconnected platform
umbilicals and connected IWOCS.
 Pulled ITC and TH crown plugs and installed 5
5.963
963” isolation sleeve .
 Pulled Venturi from flow meter mandrel, 2.75” ICV prong/ junk basket and
plug.
 Shifted AFIV-C closed with Welltec WellKey and Stroker tool.
 Set straddle sleeve in upper ICV and pressure tested annulus.
 Re-installed Venturi in flow meter mandrel.
 Recovered 5.963” isolation sleeve from IRS / Xmas Tree and installed crown
plugs.
plugs
 Disconnected IWOCS and re-installed platform umbilicals.
 Recovered IRS and 7-5/8”
/ byy 2-3/8”
/ dual riser.
13
Lessons Learned
 Main cause of NPT was the initial offshore SIT of the IRS system:
 Previous campaign had been carrying out P&A work.
 Cement had been pumped through flowhead and IRS
IRS.
 Had to completely strip down and re-build the IRS offshore.
 Helix have now implemented a policy that will no longer allow pumping of cement
through their flowhead / IRS.
IRS
 We found some leaks while RIH when testing valves from above:
 Procedure changed to install stress joint and first riser joint prior to splashing IRS,
this
hi allows
ll
allll valves
l
to b
be tested
d ffrom above.
b
 The annulus stab between the LRP and EDP had two polypak seals orientated
to hold pressure in one direction (internal).
 Had to change procedure for gas bleed off.
 Helix adding a third polypak seal to the design.
 Riser clamps were insufficient and a few were lost
lost.
14
Conclusions
 Through Tubing Intervention provided the safest, most efficient and cost
effective
ff ti option
ti tto produce
d
th
the well.
ll
 Contingency planning and testing well worth the effort
 Isolation sleeves for ICV’s
 Testing of stroker equipment
 SIT of Spool Tree and Helix IRS Interface
 Well was successfully brought on line at ± 8,000 BOPD.
15
Back up slides
16