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