Swell Packer case histories FORCE Stavanger, April 2004 Rune Freyer
Jan 18, 2016
Swell Packer case histories
FORCE Stavanger, April 2004Rune Freyer
Contents• Rubber swelling• Swell Packer • Constrictor• Installations• Applications
Rubber swelling• Thermodynamic absorption rubber/oil• Continued expansion until equilibrium• Swelling pressure 3-6bar• Reduced mechanical properties, not degradation• No swelling in pure water• Traces of oil in flowing water enough
Swelling pressure measurement
Dimensions and design• Fully flexible OD/base pipe dimensions• Small clearance (7.9-8.15” OD–8.5” hole)
Estimated/correlated ∆P
5.5”
6.625”
7”
8.15”
20406080
100120140160180200
8.5 9.5 10.5 11.5Hole ID (inch)
DP
(bar
)
4.5" base pipe
5.5" base pipe
6.625" base pipe
7" base pipe
Simulation live Simulation dead
Swell Packer for oil based mud• Delays swelling to run in hole• OBM at 106°C for 3days• 3 layer construction• 8 wells with 42 packers• So far 50-124 °C
7,15
7,35
7,55
7,75
7,95
8,15
8,35
8,55
0 1 2 3 4 5 7 10 12 14 18 26 38
Diffusion barrier + Low swellLow swell outer layerWBM Packer
2 0 °C 76 °C 10 6 °C
O il B as ed M ud C rud e 10 6 º
D iffus io n b a rrie r lo os es e ffe ct
ConstrictorTM alternative to gravel pack
• Limit annular solids transport• Avoid logistics, rig cost, fluids and risk
• Short (300mm) elements• Slide onto base pipe • Not a testable seal• +/-6” and 8.5” OH• Flexible OD
Constrictor application
Splice less cable feed through
Splice less application
PS! Better installation tool
designed shortly
Advantages• Self repairing, continues to expand• Rugged construction• Set at BHST• Logistics/setting
– No rig time, wash pipe, tools, pumping
• No environmental impact• Track record
Applications
Gravel pack Replacement
Multilateraljunction
OHCarbonate Stimulation/ water control
Replace cementin reservoir / perf
SmartWell
Mechanical inflowcontrol
OHstraddle
OHFrac
Steam control
ExpandableCH
straddle
OH screenisolation
DTS
HPHT
Gas wells
Installations• 197packers installed in 43 wells• 24 packers in 5 installations through windows• 9 wells with 64 packers verified, no failure• 41 packers installed in 8 wells in OBM
OH carbonate fracDraw down test of integrityNorsk Hydro, GraneStatoil Heidrun gravel packStatoil Snorre B smart wellStatoil Gullfaks Sat smart wellShell Nigeria 3 zone smart wellShell Malaysia OH isolationShell North Cormorant TTRD
The end
(Or just the end of the beginning…….)
Rep
eat u
nit
• Can use OBM - hole stability• Avoid annular flow – no plugging• Robust screens• Eliminate gravel pack - cheaper
Line
r han
ger
Swel
l Pac
ker
Sand
scr
eens
Con
stric
tor
Shell North CormorantCementing problemsSlim hole sidetrackIntermittent blank and preperforatedOil based mud110°CDogleg in window 18deg
TTRD Achievements 2003
CN24S3CN14S2CN32S4
CN-18S5CN-29S3
CN-13S1/2CN-17S1CA-28S3BB-14S2
CN-24S2CN-18S6
PAST TTRD wells First 2 wells 2003 Second 2 wells 2003 Fifth well 2003 Tomorrow
Past Achievements: • Max KOP 12344 ft• Max OH 3200 ft• Hole sizes 4.5” to 5”• Liner size 2 7/8” 3.5”• Bi-centre bit tech • Slotted 2-7/8” Liner• K-Formate Mud• ARC3 Real Time
PWD
Well Complexity
Well Cost
Improvements• ROP – Bits/Agitator• Directional Control• Casing Exits• Equipment Mngmnt• Mud (Micromax)• Well Control (Radar)• Abandonment
Improvements:•Mud (Micromax)
•Higher MWs >700pptf• Well Control
• New philosophy• Cementing
• A annulus isolations• Spacers improved
• Cleanout improvements
Improvements:• SqueezeCrete success• Zonal isolation with
Swelling packers• Eliminate clean-outs• Eliminate perforating
CN24s3 CN24s3 –– A Step Change in TTRD designA Step Change in TTRD design
Swelling Packers Technology (EWS)Swelling Packers Technology (EWS)CN24s3 CN24s3 -- A first in UK North Sea and in A first in UK North Sea and in
TTRD applicationTTRD applicationEliminate cementing of 2-7/8” liner and subsequent clean-out of liner
Potential for more effective zonal isolation in small hole sizes with high drawdown/differential pressuresElimination of cement debris following clean-up saving £350k – 1,000k per TTRD well (15-30% of total well cost)
Potential to eliminate perforating£400k – 750k per TTRD well for CT
Provide a step change in economics30-100% increase in VIR for slim holes
North Cormorant 12 Day WellsNorth Cormorant 12 Day Wells
12750
13000
13250
13500
13750
14000
14250
14500
14750
15000
15250
15500
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
Dril
led
Dep
th (f
eet)
AFE CN24s3
Actual CN24s3
Possible with today's technology
EXPECTATION12d wells
NORTH CORMORANTTODAY
TTRD with swelling packers completion
EXPECTATION12d wells
CN24s3 – 5th Well of TTRD campaign producing 90% OILHIGHLIGHTSHIGHLIGHTS•Milled Dual Exit Window in one successful run.
•SqueezeCrete slurry exceeded expectations for cement repair
•Excellent performance - Shoe to shoe drilling - 3.9 days Avg ROP 48fph
•New technologyBHA design – 17.5deg DLS achieved with motor & agitator
Micromax-weighted OBM. Lower ECD’s and virtually NO sag!
Swelling packers for zonal isolation – cut down on rig time and good zonal isolation
•Swelling packers – Eliminated cementing & CT perforating
•Good hole conditions through use of PWD tool.
Lost TimeLost Time• Twist-off in NMDC – however successfully fished in one run!
• Minor environmental discharge (0.6m3 oil) to sea
consequential to OBM taken through production facilities
• CT had to be used with N2 in order to lift the well offline
TODAY’S REALITY – 12 DAY WELL TIMESSwelling packers – A Step change in performance
18 5/8" casing shoe
10 3/4" liner
FBIV @ 2055,26 m MD (closed pos.)
7" blank pipe
Template
30" casing shoe
13 3/8" casing shoe
10 3 /4" casing shoe
Template funnel
10 3/4" tie-back string
ZXP packer
Swell Packerson screen joints
Liner hanger / ZXP - packer
7" screen section
Top screen PBR @ 2014,76 m MD
10 ¾” top PBR
RA tracer subSilver-110M
1.25 S.G. NaCl POLYMER BRINE
4 Swell Packers mounted onone joint of 7" blank pipe
Bullnose @ 3539 m MD
9 1/2" open hole to TD @ 3540 m MD
1.06 s.gNaCl Brine
Completion fluid for the screen section: 1,25 s.g. Na/K-COOH formate mud
RA tracer subCobalt-60
2 screen joints
10 3/4" SC-1 plug @ 300 m MD (upper barrier)
Shale intervals:2190-2240 m MD 3149-3166 m MD2290-2330 m MD 3196-3213 m MD2456-2480 m MD 3238-3274 m MD2514-2575 m MD 3310-3402 m MD2723-2767 m MD 3425-3429 m MD2802-2895 m MD
Value:Reduced cost 800kUSD/well compared to ECPs2 less runsReduced risk for installation failuresIncreased production by reduced pluggingVerified by PLT
Case 1: Swell Packers in Grane
• Emulsion• 19API crude
• Demobilize shale particles in annulus• Pressure isolation of screen annulus• 800kUSD/two runs saved/well• “Heaven compared to inflatables” (NH rigrep)
SF-37 Final Completion Diagram
FINAL WELL COMPLETION DIAGRAM @ a.h.bthfSABAH SHELL PETROLEUM CO. LTD
Well No : SF-37 Location : SFJT-BWellhead Type : Cameron Triple Wellhead + Single X’Mas treeTubing : 3.1/2” 9.2# L80 K.Fox (Conventional S/String )
Date Completed : All Depth in Ft. AH.BTHF Maximum Dev. : 63.4° @ 4426’-6784’ ahbthf
StatusMinID
Long StringDepth
3.1/2”Flow Coupling3.1/2” TRSCSSV
3 1/2” SSD
2.910
2.813
2.750
13.3/8” Casing Shoe@ 949’ 3.1/2” SPM 2.875
516
7” Seal stem located with half mu le shoe
6.250 7.000
Swell Packer
9.5/8” Casing Shoe@ 3985’
3.1/2” SPM
2.992
Swell Packer
Swell Packer
3.1/2” Bull nose 2.992
6 1/8” Open holeTD: 6784’
Blank Tubing 2.992
Swell Packer
Swell Packer
Predrilled Tubing
2.992
Blank Tubing 2.992
Top of 7” PBR3696’
2.992
2.992
2.992
2.992
2.992
2.992
3 1/2” SSD 2.750
3 1/2” X-Nipple 2.750
3 1/2” X-Nipple 2.750
3 1/2” X-Nipple 2.750
Swell Packer 2.992
999
16592100263531053606
Predrilled Tubing
Predrilled Tubing
53755366
5298
46804655
4478
43794354
40414015
3866
3700
Closed
BKR-5BKR-5
BKR-5
3.1/2” SPM 3.1/2” SPM
3.1/2” SPM 3.1/2” SPM
Closed
DKO-2DMYDMY
Closed
No Plug
No Plug
No Plug
4th July 2003
3669
SF37:SF-37's water cut has come down from ~95% to 0! This is very good proof of the packers working!
– 6-18” Open Hole– 5,7” Packer OD– 3-1/2” Lower completion
FINAL WELL COMPLETION DIAGRAM@ ah.bdf SABAH SHELL PETROLEUM CO. LTD
Well No : SF-38 Location : SFJT-BWellhead Type : Cameron Triple Wellhead + Single X’Mas treeTubing : 3.1/2” 9.2# L80 K.Fox (Conventional S/String )
Date Completed : All Depth in Ft. AH.BDF @ 71 ft elevationMaximum Dev. : 61.5° @ 4403’-7416’ ahbdf
MinIDLong StringDepth
3.1/2”Flow Coupling3.1/2” TRSCSSV
3 1/2” SSD
2.9102.813
2.750
13.3/8” Casing Shoe@ 1051’ 3.1/2” SPM + BKR-5 2.875
594
7” Seal stem located with half mule shoe
6.250
Swell Packer No.2
9.5/8” Casing Shoe@ 3484’
3.1/2” SPM + BKR-5
Swell Packer No.3
Swell Packer No.5
3.1/2” Bull nose6 1/8” Open holeTD: 7393’
Swell Packer No.7
Swell Packer No.8
2.992
Predrilled Tubing
Top of 7” PBR@ 3195’
3 1/2” SSD 2.750Sand Screens
2.992
3 1/2” SSD
2.7503 1/2” X-Nipple
Swell Packer No.4
7811440200624462855
Predrilled Tubing
Blank TubingMin ID:2.992, Max. OD: 3.900
3200
3.1/2” SPM + BKR-5 3.1/2” SPM + DKO-23.1/2” SPM + DMY
MaxOD
5.000
4.281
5.620
7.000
3.900
4.2814.000
3.905
3170
Swell Packer No.1
2.992 5.700
Blank Tubing
2.992 4.000
Blank TubingMin ID:2.992, Max. OD: 3.900
Swell Packer No.6
3 1/2” XN-Nipple 2.635 3.905Swell Packer No.9Predrilled Tubing
Blank TubingMin ID:2.992, Max. OD: 3.900
ZONE-1A
ZONE-2
ZONE-3
ZONE-4Swell Packer No.10
ZONE-1B
6855
634762756250
553553165290
456545414516
4305Blank Tubing
42344259
3610
3 1/2” X-Nipple 2.750 3.905
2.992 5.700
2.992 5.700
2.992 5.700
2.992 5.700
2.992 5.700
2.992 5.7003430
15th July 2003 SF-38 Final Completion
Diagram
1500 BOPD against 1400 promised
0% water cut Sand = 2 pptb
545 psi FTHP (so there's plenty of room to bean up from current 28/64")
GOR = 238 scf/STB
The GOR is VERY encouraging because there is a gas sand present.
This GOR is LOWER than many Rev. 2 wells with more expensive completions.
SF Rev3 Budget versus EFC
47
66
-
10
20
30
40
50
60
70
Budget EFC
Wel
l Cos
t RM
'000 SF 39
SF 38SF 37
-29%
Cost Performance
SF Average well cost comparison
16
21
0
5
10
15
20
25
Well cost Rev2 Well cost Rev3
Wel
l Cos
t (R
M M
illio
n)
BudgetEFC
-26%
Savings on:- Liners- Cement- Cleanout- ESS (now Poromax)- Scraper runs- Perforation runs- Packers- Completion equipment
Cost Performance
SF Rev.2 and Rev.3 BenchmarkingCost per foot (Rm/ft) comparison
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
SF-31 SF-32 SF-33 SF-34 SF-35 SF-36 SF-37 SF-38 SF-39 AvgRev2
AvgRev3
RM
per
ft
Budget
Actual (EFC)
+2% -29%
Conclusions
– Significantly Cheaper Wells– Installation relatively easy– Production / Packer working very encouraging– Can do even cheaper
Snorre B Well D-4H Completion schematic
Drawing: 1 Date: 18.09.2003File: D-4Hcomplettering skisse.pptRev: 3
Packer depths:
Prod. Packer: 3192 m MDIso. packer #1: 3586 m MDIso. packer #2: 4116 m MDIso. packer #3: 4611 m MD
TOC = 3013 m MD
Casing depths:13 3/8”: 380 – 2178 m MD
Liner depths:9 5/8” liner: 2111.5 – 4273 m MD7x5 1/2” screen: 4347 – 4973 m MD
Tubing:7”, 13 Cr-80, 29 lbs/ft NSCC5 ½”, 13 Cr-80, 20 lbs/ft Vam Top5 ½”, 13 Cr-80, 23 lbs/ft Vam Top4 ½”, 13 Cr-80, 13.5 lbs/ft NSCT
7” DHSV@ 606 m MD
5 ½”
Lunde
ClampsPP
@ 3
192
m
IP @
358
6 m
IP @
411
6 m
IP @
461
1 m
4 ½”
7” tubing
Sone #4Sone #3Sone #2Sone #1
5 ½”5 ½”
Swell Packers
Value:Sand production expected in perforations at water onset
Reduced erosion risk of smart well equipmentNo down hole operations during installationLong packers ensure efficient sealingVerified by downhole gauges
Case 2: Down hole test
• 8,15” OD WBM, 7” perforated liner• 8-1/2” Open hole • Coiled tubing deployed test plug• Successfully inflow tested• February 2003
P
Case 3: Isolation in Carbonates (1/3)2380 meters horizontal reservoir section
8-1/2" Hole9-5/8” Casing Shoe
WBM, 7.9” OD5-1/2” preperforated liner
Case 3: Isolation in Carbonates (2/3)
3-1/2” Inner isolation string (2.992” ID) SSD (OD - 3.92”, ID - 2.31”)WBM 4,4” x 3-1/2” - 4m
Case 3: Isolation in Carbonates (3/3)
8-1/2" Hole9-5/8” Casing Shoe
5-1/2" Perforated liner3.5" tubing
Liner – Annulus IsolationTubing – Liner Isolation Isolated and controlled production interval
Hole ID DP [bar] %
Swell Packer simulations 5.73 246 305.742 0 1 20.0 % 5.77 196 405.753 1 1 22.0 % 5.80 156 48
For: 5.765 1 2 24.0 % 5.83 116 57Date: 5.776 1 2 26.0 % 5.87 76 69
By: 5.788 1 2 28.0 % 5.93 36 855.799 1 3 30.0 %5.811 1 3 32.0 %
Input 5.822 2 4 34.0 % 5.99 16 102Pipe OD 5.000 in 127 mm 5.834 2 4 36.0 %Packer OD 5.625 in 143 mm 5.845 2 5 38.0 % DP [Psi]
5.856 2 5 40.0 % 3567Down hole viscosity 1.50 cP 5.868 2 6 42.0 % 2842Hole ID 6.000 in 152.4 mm 5.879 3 6 44.0 % 2262Operational pressure 50 bar 5.890 3 7 46.0 % 1682
5.902 3 7 48.0 % 11025.913 3 8 50.0 % 522
Output 5.924 4 9 52.0 %Final OD (20bar DP) 6.031 in 153.2 mm 5.935 4 9 54.0 %Volume swell % at Hole ID 106% 5.946 4 10 56.0 % 232Time to fully set max DP 35 days 5.958 5 11 58.0 %Time to operational pressure N/A days 5.969 5 12 60.0 %Time to first seal 15 days 5.980 5 13 62.0 %DP at "Hole ID" 212 psi 15 bar a 5.991 6 13 64.0 %
6.002 6 14 66.0 %6.013 6 15 68.0 %
Input 6.024 7 16 70.0 %Cable OD 0.25 in 6.350 mm 6.035 7 17 72.0 %Number of cables 2 Insufficient rubber thickness 6.046 8 18 74.0 %
6.057 8 19 76.0 %Pressure calculations are based on failure pressure of a 3m long element, modified with 20% safety factor. 6.068 8 20 78.0 %A longer packer will enable higher differential pressure but exact correlations are not mapped. 6.079 9 21 80.0 %Timing of swelling process will vary dependent of fluid circulation and is based on WBM construction. 6.090 9 22 82.0 %Timing of swelling in gas may be estimated by EWSOBM construction will take longer time. 6.101 10 23 84.0 %EWS advise designs with differential pressure exceeding simulated limitations also allowing for washouts. 6.112 10 24 86.0 %
6.122 11 26 88.0 %Oil Field Units SI Units 6.133 11 27 90.0 %
Temperature 280.4 °F 138 °CBase pipe wt 12.6 ppf 18.8 kg/mBase pipe length 19.7 ft 6 mElement length 9.8 ft 3 mPacker weight excl pipe 26.2 lbs 11.9 kgPacker mass 274.3 lbs 124.5 kgPacker volume 0.357 ft^3 0.010 115%
Differential pressure profile
0
50
100
150
200
250
300
5.70 5.75 5.80 5.85 5.90 5.95 6.00
Hole ID [in]
Diff
eren
tial p
ress
ure
[bar
]
0
500
1000
1500
2000
2500
3000
3500
4000
Diff
eren
tial p
ress
ure
[Psi
]
Swell profile
0
5
10
15
20
25
30
5.70 5.75 5.80 5.85 5.90 5.95 6.00 6.05 6.10 6.15 6.20
Hole ID [in]
Tim
e to
sw
ell [
days
]
Time to sealTime to fully set
Splice less cable feed through• Competent formation• One string• No cable splicing at packers