Swell Packer Case Histories

Swell Packer case histories FORCE Stavanger, April 2004 Rune 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

DP (bar)

8.15”

200 180 160 140 120 100 80 60 40 20

4.5" base pipe 5.5”

5.5" base pipe 6.625" base pipe 7" base pipe

6.625”

7”

8.5

9.5

10.5 Hole ID (inch)

Simulation live

Simulation dead

11.5

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

8,55 8,35

O il B a s e d M ud

8,15

2 0 °C

7 6 °C

C rud e 1 0 6 º

1 0 6 °C

Diffusion barrier + Low swell

7,95

Low swell outer layer WBM Packer

7,75 7,55

D iffus io n b a rrie r lo o s e s e ffe c t

7,35 7,15 0

1

2

3

4

5

7

10

12

14

18

26

38

TM

Constrictor

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 OH Carbonate Stimulation/ water control

CH straddle

Gravel pack Replacement Mechanical inflow control OH screen isolation

OH straddle

Smart Well

Multilateral junction OH Frac

HPHT Steam DTS control Expandable

Replace cement in reservoir / perf 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 frac Draw down test of integrity Norsk Hydro, Grane Statoil Heidrun gravel pack Statoil Snorre B smart well Statoil Gullfaks Sat smart well Shell Nigeria 3 zone smart well Shell Malaysia OH isolation Shell North Cormorant TTRD

The end (Or just the end of the beginning…….)

Swell Packer

Constrictor

Repeat unit

Can use OBM - hole stability Avoid annular flow – no plugging Robust screens Eliminate gravel pack - cheaper

Sand screens

Liner hanger

• • • •

Shell North Cormorant Cementing problems Slim hole sidetrack Intermittent blank and preperforated Oil based mud 110°C Dogleg in window 18deg

TTRD Achievements 2003 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

CN-18S5 CN-29S3 CN-13S1/2 CN-17S1 CA-28S3 BB-14S2 PAST TTRD wells

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

Well Complexity

Well Cost

CN-24S2 CN-18S6 First 2 wells 2003

CN14S2 CN32S4 Second 2 wells 2003

CN24S3 Fifth well 2003

Tomorrow

CN24s3 – A Step Change in TTRD design Swelling Packers Technology (EWS) CN24s3 - A first in UK North Sea and in TTRD application ¾Eliminate cementing of 2-7/8” liner and subsequent clean-out of liner ¾Potential for more effective zonal isolation in small hole sizes with high drawdown/differential pressures ¾Elimination of cement debris following clean-up saving £350k – 1,000k per TTRD well (15-30% of total well cost)

¾Potential to eliminate perforating ¾£400k – 750k per TTRD well for CT

¾Provide a step change in economics ¾30-100% increase in VIR for slim holes

North Cormorant 12 Day Wells CN24s3 – 5th Well of TTRD campaign producing 90% OIL HIGHLIGHTS •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 technology 9BHA design – 17.5deg DLS achieved with motor & agitator 9Micromax-weighted OBM. Lower ECD’s and virtually NO sag! 9Swelling 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. 1

Lost Time

12750

• Twist-off in NMDC – however successfully fished in one run!

13250

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

19

20

21

22

23

24

25

26

27

28

29

13750 Drilled Depth (feet)

consequential to OBM taken through production facilities

18

NORTH CORMORANT TODAY TTRD with swelling packers completion

13000

13500

• Minor environmental discharge (0.6m3 oil) to sea

17

• CT had to be used with N2 in order to lift the well offline

14000

14250

14500

14750

15000

TODAY’S REALITY – 12 DAY WELL TIMES

15250

15500

Swelling packers – A Step change in performance

EXPECTATION EXPECTATION 12d wells 12d wells

AFE CN24s3 Actual CN24s3 Possible with today's technology

30

Completion fluid for the screen section: 1,25 s.g. Na/K-COOH formate mud Template funnel Template Shale intervals: 2190-2240 m MD 2290-2330 m MD 2456-2480 m MD 2514-2575 m MD 2723-2767 m MD 2802-2895 m MD

10 3/4" SC-1 plug @ 300 m MD (upper barrier) 30" casing shoe 1.06 s.g NaCl Brine

3149-3166 m MD 3196-3213 m MD 3238-3274 m MD 3310-3402 m MD 3425-3429 m MD

Value:

18 5/8" casing shoe

Reduced cost 800kUSD/well compared to ECPs 2 less runs Reduced risk for installation failures Increased production by reduced plugging Verified by PLT

10 3/4" tie-back string 10 ¾” top PBR

ZXP packer 10 3/4" liner

Swell Packers on screen joints

13 3/8" casing shoe

RA tracer sub Silver-110M

RA tracer sub Cobalt-60

Top screen PBR @ 2014,76 m MD Bullnose @ 3539 m MD

2 screen joints Liner hanger / ZXP - packer FBIV @ 2055,26 m MD (closed pos.) 1.25 S.G. NaCl POLYMER BRINE

10 3 /4" casing shoe

7" blank pipe

4 Swell Packers mounted on one joint of 7" blank pipe

7" screen section 9 1/2" open hole to TD @ 3540 m MD

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)

SABAH SHELL PETROLEUM CO. LTD FINAL WELL COMPLETION DIAGRAM @ a.h.bthf Well No : SF-37 Location : SFJT-B Wellhead Type : Ca meron Triple Wellhead + Single X’Mas tree Tubing : 3.1/2” 9.2# L80 K.Fo x (Conventional S/String )

Date Co mp leted : 4th July 2003 All Depth in Ft. AH.BTHF Maximu m Dev. : 63.4° @ 4426’-6784’ ahbthf

Depth

13.3/8” Casing Shoe @ 949’

Top of 7” PBR 3696’

Long String

M in ID

3.1/2”Flow Coupling

2.910

Status

516 3.1/2” TRSCSSV

2.813

999

3.1/2” SPM

2.875 BKR-5

1659 2100 2635 3105

3.1/2” SPM

BKR-5 BKR-5 DKO-2

3.1/2” SPM

DM Y

3606

3.1/2” SPM

DM Y

3669

3700

3.1/2” SPM 3.1/2” SPM

3 1/2” SSD

7” Seal stem located with half mu le shoe

2.750

Closed

7.000

Closed

3 1/2” SSD

2.750

4015 4041

Swell Packer

2.992

3 1/2” X-Nipple

2.750

9.5/8” Casing Shoe @ 3985’

4354 4379 4478 4655 4680 5298

Predrilled Tubing

2.992

Swell Packer

2.992

3 1/2” X-Nipple

2.750

Blank Tubing

2.992

Swell Packer

2.992

Predrilled Tubing

2.992

Swell Packer

2.992

3 1/2” X-Nipple

2.750

Blank Tubing

2.992

Swell Packer

2.992

Predrilled Tubing

2.992

5366

Swell Packer

2.992

5375

3.1/2” Bull nose

2.992

6 1/8” Open hole TD: 6784’

– 6-18” Open Hole – 5,7” Packer OD – 3-1/2” Lower completion

Closed

6.250

3866

SF-37 Final Completion Diagram

No Plug

No Plug

No Plug

SF37: SF-37's water cut has come down from ~95% to 0! This is very good proof of the packers working!

SABAH SHELL PETROLEUM CO. LTD FINAL WELL COMPLETION DIAGRAM@ ah.bdf

15th July 2003 Date Completed : All Depth in Ft. AH.BDF @ 71 ft elevation Maximum Dev. : 61.5° @ 4403’-7416’ ahbdf

Well No : SF-38 Location : SFJT-B Wellhead Type : Cameron Triple Wellhead + Single X’Mas tree Tubing : 3.1/2” 9.2# L80 K.Fox (Conventional S/String )

Max OD

3.1/2”Flow Coupling 3.1/2” TRSCSSV

Min ID 2.910 2.813

781 3.1/2” SPM + BKR-5

2.875

5.620

Depth

594 13.3/8” Casing Shoe @ 1051’

Top of 7” PBR @ 3195’

1440 2006 2446 2855

3.1/2” SPM + BKR-5 3.1/2” SPM + BKR-5 3.1/2” SPM + DKO-2 3.1/2” SPM + DMY

3170

3 1/2” SSD

3200

9.5/8” Casing Shoe @ 3484’

ZONE-1A

ZONE-1B Blank Tubing Min ID:2.992, Max. OD: 3.900

3430 3610 4234 4259 4305 4516 4541 4565

ZONE-2

Blank Tubing Min ID:2.992, Max. OD: 3.900 ZONE-3

Blank Tubing Min ID:2.992, Max. OD: 3.900 ZONE-4

5290 5316 5535 6250 6275 6347

5.000

1500 BOPD against 1400 promised 0% water cut 2.750

4.281

7” Seal stem located with half 6.250 mule shoe

7.000

3 1/2” X-Nipple Swell Packer No.1 Sand Screens Swell Packer No.2 3 1/2” SSD Blank Tubing Swell Packer No.3 Blank Tubing Swell Packer No.4 3 1/2” SSD Swell Packer No.5

Predrilled Tubing

6855 6 1/8” Open hole TD: 7393’

Long String

Swell Packer No.6 3 1/2” X-Nipple Swell Packer No.7 Predrilled Tubing Swell Packer No.8 3 1/2” XN-Nipple Swell Packer No.9 Predrilled Tubing Swell Packer No.10 3.1/2” Bull nose

SF-38 Final Completion Diagram Sand = 2 pptb

545 psi FTHP (so there's plenty of room to bean up from current 28/64")

2.750 2.992

3.905 5.700

GOR = 238 scf/STB

2.750 2.992

4.281 4.000

2.992

5.700

The GOR is VERY encouraging because there is a gas sand present.

2.992 2.992

5.700 3.900

2.750 2.992

3.905 5.700

2.992 2.635 2.992

5.700 3.905 5.700

2.992

5.700

2.992

4.000

This GOR is LOWER than many Rev. 2 wells with more expensive completions.

SF Rev3 Budget versus EFC

Well Cost RM'000

Cost Performance

66

70 60

47

50 -29%

40

SF 39 SF 38 SF 37

30 20 10 Budget

SF Average well cost comparison 25

Budget EFC

Well Cost (RM Million)

21 20 -26%

16

15 10 5 0 Well cost Rev2

Well cost Rev3

EFC

Savings on: - Liners - Cement - Cleanout - ESS (now Poromax) - Scraper runs - Perforation runs - Packers - Completion equipment

Cost Performance SF Rev.2 and Rev.3 Benchmarking Cost per foot (Rm/ft) comparison 5000 Budget

4500

Actual (EFC)

4000

RM per ft

3500 3000

+2%

-29%

Avg Rev2

Avg Rev3

2500 2000 1500 1000 500 0 SF-31

SF-32

SF-33

SF-34

SF-35

SF-36

SF-37

SF-38

SF-39

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: 18.09.2003 File: D-4Hcomplettering skisse.ppt Rev: 3

Value: Packer depths: 7” DHSV @ 606 m MD

Clamps

Casing depths: 13 3/8”: 380 – 2178 m MD

Sand production expected Prod. Packer: 3192 m MD in perforations at water onset Iso. packer #1: 3586 m MD Liner depths: Reduced erosion risk of smart well equipment Iso. packer #2: 4116 m MD 9 5/8” liner: 2111.5 – 4273 m MD No down hole operations during installation Iso. packer #3: 4611 m MD 7x5 1/2” screen: 4347 – 4973 m MD Long packers ensure efficient sealing TOC = 3013 m MD Tubing: Verified by downhole gauges 7”, 13 Cr-80, 29 lbs/ft NSCC

5 ½”

5 ½”

Sone #1

5 ½”

Sone #2

IP @ 4611 m

IP @ 4116 m

ub in g

PP @ 3192 m

7” t

IP @ 3586 m

5 ½”, 13 Cr-80, 20 lbs/ft Vam Top 5 ½”, 13 Cr-80, 23 lbs/ft Vam Top 4 ½”, 13 Cr-80, 13.5 lbs/ft NSCT

Swell Packers

4 ½”

Sone #3

Sone #4

Lunde

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" Hole

9-5/8” Casing Shoe WBM, 7.9” OD 5-1/2” preperforated liner

Case 3: Isolation in Carbonates (2/3)

3-1/2” Inner isolation string (2.992” ID)

WBM 4,4” x 3-1/2” - 4m

SSD (OD - 3.92”, ID - 2.31”)

Case 3: Isolation in Carbonates (3/3) 9-5/8” Casing Shoe

8-1/2" Hole

3.5" tubing

Liner – Annulus Isolation Tubing – Liner Isolation

5-1/2" Perforated liner

Isolated and controlled production interval

Hole ID

Differential pressure profile 5.742 300

Differential pressure [bar]

For: Date: By:

Input Pipe OD Packer OD

5.000 in 5.625 in

Down hole viscosity Hole ID Operational pressure

1.50 cP 6.000 in 50 bar

127 mm 143 mm

152.4 mm

Output Final OD (20bar DP) Volume swell % at Hole ID Time to fully set max DP Time to operational pressure Time to first seal DP at "Hole ID"

N/A

6.031 in 106% 35 days days 15 days 212 psi

153.2 mm

15 bar

Input Cable OD Number of cables

0.25 in 2

6.350 mm Insufficient rubber thickness

Time to swell [days]

Pressure calculations are based on failure pressure of a 3m long element, modified with 20% safety factor. A longer packer will enable higher differential pressure but exact correlations are not mapped. Timing of swelling process will vary dependent of fluid circulation and is based on WBM construction. Timing of swelling in gas may be estimated by EWS EWS advise designs with differential pressure exceeding simulated limitations also allowing for washouts.

Oil Field Units 280.4 12.6 19.7 9.8 26.2 274.3 0.357

SI Units °F ppf ft ft lbs lbs ft^3

138 18.8 6 3 11.9 124.5 0.010

°C kg/m m m kg kg 115%

5.73

246

30

20.0 %

5.77

196

40

22.0 % 24.0 % 26.0 % 28.0 % 30.0 % 32.0 % 34.0 % 36.0 % 38.0 % 40.0 % 42.0 % 44.0 % 46.0 % 48.0 % 50.0 % 52.0 % 5.8554.0 % Hole ID56.0 [in] % 58.0 % 60.0 % 62.0 % 64.0 % Swell profile 66.0 % 68.0 % 70.0 % 72.0 % 74.0 % 76.0 % 78.0 % 80.0 % 82.0 %

5.80 5.83 5.87 5.93

156 116 76 36

1

1 1 1 1 1 1 2 2 2 2 2 3 3 3 3 4 5.75 4 4 5 5 5 6 6 6 7 7 8 8 8 9 9

1 2 2 2 3 3 4 4 5 5 6 6 7 7 8 9 95.80 10 11 12 13 13 14 15 16 17 18 19 20 21 22

4000 3500 3000

5.99

16

2500

DP [Psi] 2000 3567 1500 2842 22621000 1682 1102500 522 5.90

0 6.00

5.95

232

15

6.101 6.112 10 6.122 6.133

OBM construction will take longer time.

Temperature Base pipe wt Base pipe length Element length Packer weight excl pipe Packer mass Packer volume

a

5.753 5.765 5.776 250 5.788 5.799 200 5.811 5.822 5.834 150 5.845 5.856 100 5.868 5.879 5.890 50 5.902 5.913 0 5.924 5.70 5.935 5.946 5.958 5.969 5.980 5.991 6.002 6.013 6.024 30 6.035 6.046 25 6.057 6.068 20 6.079 6.090

0

10 10 11 11

23 24 26 27

84.0 % 86.0 % 88.0 % 90.0 %

5

0 5.70

5.75

5.80

5.85

5.90

5.95

Hole ID [in]

6.00

6.05

6.10

6.15

6.20

Time to seal Time to fully set

48 57 69 85

Differential pressure [Psi]

Swell Packer simulations

DP [bar] %

102

Splice less cable feed through • Competent formation • One string • No cable splicing at packers