wif categorization exercise · 2018-01-17 · acceptance criteria. 16 example 5 wif well integrity...

WIF Categorization Exercise

Svein Inge Rafoss, Leading advisor well integrity completion and intervention, Statoil

WIF Well Integrity Workshop, May 26, 2011

2

Category Principles & Colours


Category Principle

RedOne barrier failure and the other is degraded/not verified, or leak to surface.

Orange One barrier failure and the other is intact, or a single failure may lead to leak to surface.

Yellow One barrier degraded, the other is intact.

Green Healthy well - no or minor issue.

3

Group 1

Group 2

Group 3

Group 4

Group 5

Group 6

Group 7

Group 8

Group 9

Group 10

Group 11

RNNPreported

Ex 1 o o o o o o o

Ex 2 o

Ex 3 o o o

Ex 4

Ex 5 o o o o o o o o o o

Ex 6

Ex 7 o

Ex 8 o o o o o o o o o

4

Group 1

Group 2

Group 3

Group 4

Group 5

Group 6

Group 7

Group 8

Group 9

RNNPreported

Ex 1

Ex 2

Ex 3

Ex 4

Ex 5

Ex 6

Ex 7

Ex 8

5

X-mastree

PWV

HMV

MMV

KVPT

PT

PI

A B C

PI

9 5/8" - window @ 2500m MD/2058m TVD

Prod Packer @ 2407m MD/ 1994m TVD

FIT @ 9 5/8" shoe N/A sg

FIT @ 13 3/8" shoe 1.71 sg

7" liner hanger packer @ 2440m MD

DHSV nipple @ 280m MD

TOC 9 5/8” @ 2195m MD/1848m TVD

FG @ Prod packer 1.xx sg

SV

13 3/8" @ 2181m MD/1838m TVD

TOC 13 3/8" @ N/A m MD

20" @ 732m MD

SV

Seal stem @ 2438m MD

Example 1

• 9 year old platform Oil Producer• DHSV: Testing within leak criteria• Christmas Tree: Testing within leak

criteria• A-Annulus valve: Testing within leak

criteria• Completion string & Production

packer: Testing within leak criteria• Formation at intermediate casing:

Formation Strength can not withstand max pressure from reservoir (with oil column)

• Production casing: Buttress threads• Wellhead & Tubing hanger: Leak

tight. • Casing cement: Poor sealing cement

outside the 9 5/8” casing• B-Annulus: Hydrocarbons build up in

B annulus. Pressure buildup less than API criteria.

• C-Annulus: No pressure

WIF Well Integrity 2009 Workshop, May 28, 2009

Primary Barriers

Fm strength at 9 5/8” shoe

9-5/8” casing (below prod pkr)

9-5/8” casing cement (up to prod pkr)

Production packer

Prod tubing

DHSV

Secondary Barriers

Formation at prod packer

9-5/8” casing (above prod pkr)

9-5/8” casing cement (above prod packer)

Tubing hanger

Wellhead

XMT

: failed/suspected failed barrier element

6

X-mastree

PWV

HMV

MMV

KVPT

PT

PI

A B C

PI

9 5/8" - window @ 2500m MD/2058m TVD



FIT @ 13 3/8" shoe 1.71 sg



TOC 9 5/8” @ 2195m MD/1848m TVD


SV

13 3/8" @ 2181m MD/1838m TVD

TOC 13 3/8" @ N/A m MD

20" @ 732m MD

SV


Example 1

• 9 year old platform Oil Producer• DHSV: Testing within leak criteria• Christmas Tree: Testing within

leak criteria• A-Annulus valve: Testing within

leak criteria• Completion string & Production

packer: Testing within leak criteria• Formation at intermediate casing:

Formation Strength can not withstand max pressure from reservoir (with oil column)

• Production casing: Buttress threads

• Wellhead & Tubing hanger: Leak tight.

• Casing cement: Poor sealing cement outside the 9 5/8” casing

• B-Annulus: Hydrocarbons build up in B annulus. Pressure buildup less than API criteria.

• C-Annulus: No pressure


Primary Barriers




Production packer

Prod tubing

DHSV

Secondary Barriers




Tubing hanger

Wellhead

XMT


7

X-mastree

PWV

HMV

MMV

KVPT

PT

PI

A B C

PI

9 5/8" - window @ 2500m MD/2058m TVD



FIT @ 13 3/8" shoe 1.71 sg



TOC 9 5/8” @ 2195m MD/1848m TVD


SV

13 3/8" @ 2181m MD/1838m TVD

TOC 13 3/8" @ N/A m MD

20" @ 732m MD

SV


Example 1



8

Example 2

• 3 year old subsea Oil Producer

• DHSV: Testing within leak criteria

• PMV: Leak rate exceeds API criteria

• PWV, XOV, CIV,AMV: Testing within leak criteria. Tested monthly.

• Completion string & Production packer: Testing within leak criteria

• Production casing, Wellhead & Tubing hanger: Leak tight

• Casing cement: In compliance with Norsok D-010


A B C

13 3/8" csg @ 2320m MD/2103m TVD

TOC 13 3/8” @ 1912m MD/ 1769m TVD. See note 3.

10 3/4"-9 5/8" XOV @ 444m MD

9 5/8" csg @ 5465m MD/4318m TVD

TOC 9 5/8” @ 4500m MD/3643m TVD. See note 2.

7" liner hanger @ 5271m MD/4181m TVD

Prod. packer @ 5211m MD/4134m TVD

TOC 7” @ 5478m MD/4325m TVD. See note 1.

DHSV @ 353m MD

FIT @13 3/8” shoe 1.87 sg

FIT @ 9 5/8” shoe 1.84 sg

PBR @ 5195m MD

Perforations@ 5520 6159 MD

20" csg @ 909,6m MD/ 905,4m TVD


LOT @ 20” shoe 1.46 sg

AWV

PMVAMV

Horizontal x-mas tree

XOV

WOV

Tbghng plug

Debris Cap

ITC with plug

PT

PT

TCI

THI MIV

HXTextension

CIV1

min @ 5465m MD/ 4318m TVD 1.97 sg.

min @ 5211m MD/ 4134m TVD 1.97 sg.

PWV

PMV leak above accept criteria. See Disp below. PWV holds test criteria. PWV, XOV, CIV and MIV tests once per month.

min 1.71 sg.

Primary Barriers

Cap Rock

Liner Cement

Liner Hanger




Production packer

Prod tubing. Includes PBR (not qualified)

DHSV

Secondary Barriers




Tubing hanger/seals/plug

Wellhead

XMT/valves


9

Example 2

• 3 year old subsea Oil Producer

• DHSV: Testing within leak criteria

• PMV: Leak rate exceeds API criteria

• PWV, XOV, CIV,AMV: Testing within leak criteria. Tested monthly.

• Completion string & Production packer: Testing within leak criteria

• Production casing, Wellhead & Tubing hanger: Leak tight

• Casing cement: In compliance with Norsok D-010


A B C

13 3/8" csg @ 2320m MD/2103m TVD

TOC 13 3/8” @ 1912m MD/ 1769m TVD. See note 3.

10 3/4"-9 5/8" XOV @ 444m MD

9 5/8" csg @ 5465m MD/4318m TVD

TOC 9 5/8” @ 4500m MD/3643m TVD. See note 2.

7" liner hanger @ 5271m MD/4181m TVD

Prod. packer @ 5211m MD/4134m TVD


DHSV @ 353m MD

FIT @13 3/8” shoe 1.87 sg

FIT @ 9 5/8” shoe 1.84 sg

PBR @ 5195m MD

Perforations@ 5520 6159 MD

20" csg @ 909,6m MD/ 905,4m TVD


LOT @ 20” shoe 1.46 sg

AWV

PMVAMV

Horizontal x-mas tree

XOV

WOV

Tbghng plug

Debris Cap

ITC with plug

PT

PT

TCI

THI MIV

HXTextension

CIV1

min @ 5465m MD/ 4318m TVD 1.97 sg.

min @ 5211m MD/ 4134m TVD 1.97 sg.

PWV

PMV leak above accept criteria. See Disp below. PWV holds test criteria. PWV, XOV, CIV and MIV tests once per month.

min 1.71 sg.

Primary Barriers

Cap Rock

Liner Cement

Liner Hanger




Production packer

Prod tubing. Includes PBR (not qualified)

DHSV

Secondary Barriers




Tubing hanger/seals/plug

Wellhead

XMT/valves


10

Example 3• Original well from 1979• Old casings incl 9-5/8 with

buttress treads.• Class B cement (Old cement

without silica, known to crack up over time)

• Re-completed in 2011, due to leak from Vidar formation into Annulus B with pressure potential above 3500 psi at surface

• New 7 casing with premium threads

• No ASV (deviation), on gaslift• Vidar formation taken into

production below packer (overshot without seals)

• No pressure build-up in Annulus B after re-completed.

WIF Well Integrity 2011 Workshop, May 26

11

Example 3• Original well from 1979• Old casings incl 9-5/8 with buttress

treads.• Class B cement (Old cement without

silica, known to crack up over time)• Re-completed in 2011, due to leak

from Vidar formation into Annulus B with pressure potential above 3500 psi at surface

• New 7 casing with premium threads• No ASV (deviation), on gaslift• Vidar formation taken into production

below packer (overshot without seals)• No pressure build-up in Annulus B

after re-completed.

• Categorized by COPNO as Yellow due to common barrier and one failure can lead to gas leak to other annuli (no gas tight threads from 9-5/8 and out)


12

Example 4• Drilled and completed in 2008.

• Deviated well bore – max DLS 4 deg / 100 ft.

• CT fishing operation in 2009 pushed plug (TTRBP) to bottom of liner section – below perfs. (Total 3 CT Runs).

• CT Straddle Stimulation performed in 2010. (Total 13 Runs)

• 40 Finger Multi-fingered calliper run across full tubing length after CT Straddle Stim.

• Multi-fingered calliper results identified a maximum grooved wall penetration of 47% at 1,626’ with cross-sectional area loss of 5%.


13

• New values of Burst, Tension and Collapse calculated and re-modelled within WellCat to verify safety factors.

• 7500 psi tubing re-stimulation burst safety factor identified to be lower than company safety factor of 1.200.

• 6000 psi tubing re-stimulation case modelled and found to give an acceptable burst safety factor.

• Permanent non-conformance created on well and findings communicated to Drilling / Completion / Intervention and Production Groups.

Example 4


14

• New values of Burst, Tension and Collapse calculated and re-modelled within WellCat to verify safety factors.

• 7500 psi tubing re-stimulation burst safety factor identified to be lower than company safety factor of 1.200.

• 6000 psi tubing re-stimulation case modelled and found to give an acceptable burst safety factor.

• Permanent non-conformance created on well and findings communicated to Drilling / Completion / Intervention and Production Groups.

• WIF Categorization…

Example 4


15

Example 5


Tubing to annulus leak above API acceptance criteria

16

Example 5


Tubing to annulus leak above API acceptance criteria

17

Example 6


Producer on Gas lift.

Inflow test of A-annulus failed.

Leak detection tool found communication @ lower GLV 2628 m md.

Unable to pull GLV

Plug installed below lowest GLV @ 2772 m MD. Inflow tested OK.

18

Example 6

• Green WellPrimary Barrier:

PackerTubing below plugInflow tested Plug

Secondary Barrier:Prod casingWellheadX-mas tree


19

Example 7


• Subsea/tieback well, failed on initial production. Well was completed in September/October 1998 and attempted put on production 24.12.98. During production the surface wellhead lifted approx. 32 cm. Caused by the thermal expansion and the fact that the 9 5/8” lock ring in subsea wellhead is not locked in the wellhead. In addition, the 13 3/8” x 9 5/8” annulus is a closed volume as pressure is not bled off into the formation below the 13 3/8” casing shoe.

• P/A Operation in 1999. The well was killed and the production tubing down to the packer was pulled. The perforated intervals were isolated with cement and casing isolated with cement plugs.

• 2007 Small fluid leak observed from annulus B (from WH inspection port)

• October 2010 Small gas leak observed from annulus (HC gas)

20 WIF Well Integrity Workshop, May 26, 2011

• Subsea/tieback well, failed on initial production. Well 15/12-A-02 (exploration well 15/12-6S) was completed in September/October 1998 and attempted put on production 24.12.98. During production the surface wellhead lifted approx. 32 cm. Caused by the thermal expansion and the fact that the 9 5/8” lock ring in subsea wellhead is not locked in the wellhead. In addition, the 13 3/8” x 9 5/8”annulus is a closed volume as pressure is not bled off into the formation below the 13 3/8”casing shoe.

• P/A Operation in 1999. The well was killed and the production tubing down to the packer was pulled. The perforated intervals were isolated with cement and casing isolated with cement plugs.

• 2007 Small fluid leak observed from annulus B (from WH inspection port)

• October 2010 Small gas leak observed from annulus (HC gas)

Example 7

21

Example 8


SV

13 3/8” csg

KWV PWV

UMV

LMVX-mas

tree

DHSV

9 5/8” csg

FG = 2,15 SG

FIT = 1,88 SG

7” liner

4 1/2” liner

FIT = 1,80 SG

Prod. packer

SV

13 3/8” csg

KWV PWV

UMV

LMVX-mas

tree

DHSV

9 5/8” csg

FG = 2,15 SG

FIT = 1,88 SG

7” liner

4 1/2” liner

FIT = 1,80 SG

Prod. packer

SV

13 3/8” csg

KWV PWV

UMV

LMVX-mas

tree

DHSV

9 5/8” csg

FG = 2,15 SG

FIT = 1,88 SG

7” liner

4 1/2” liner

FIT = 1,80 SG

Prod. packer

Primary Barrier

Cemented Liner, casing

Liner Top Packer

Tubing above the DHSV

DHSV

Production packer

Casing

Secondary Barrier

Cemented Casing, liner

Wellhead

Tubing Hanger

Annulus Valve

Xmas tree

•22th of October 2009, water injection was started up after a shut in. After 90 minutes the annulus pressure raised immediately to injection pressure. A tubing to annulus communication was determined.

•Obtained a good inflow test on the DHSV

22

Example 8

WIF Well Integrity Workshop, May 26, 2011WIF Well Integrity Workshop, May 26, 2011

SV

13 3/8” csg

KWV PWV

UMV

LMVX-mas

tree

DHSV

9 5/8” csg

FG = 2,15 SG

FIT = 1,88 SG

7” liner

4 1/2” liner

FIT = 1,80 SG

Prod. packer

SV

13 3/8” csg

KWV PWV

UMV

LMVX-mas

tree

DHSV

9 5/8” csg

FG = 2,15 SG

FIT = 1,88 SG

7” liner

4 1/2” liner

FIT = 1,80 SG

Prod. packer

SV

13 3/8” csg

KWV PWV

UMV

LMVX-mas

tree

DHSV

9 5/8” csg

FG = 2,15 SG

FIT = 1,88 SG

7” liner

4 1/2” liner

FIT = 1,80 SG

Prod. packer

Primary Barrier

Cemented Liner, casing

Liner Top Packer

Tubing above the DHSV

DHSV

Production packer

Casing

Secondary Barrier

Cemented Casing, liner

Wellhead

Tubing Hanger

Annulus Valve

Xmas tree

•22th of October 2009, water injection was started up after a shut in. After 90 minutes the annulus pressure raised immediately to injection pressure. A tubing to annulus communication was determined.

•Obtained a good inflow test on the DHSV

wif categorization exercise · 2018-01-17 · acceptance criteria. 16 example 5 wif well integrity...

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