WIF Categorization Exercise. Svein Inge Rafoss, Leading advisor well integrity completion and intervention, Statoil

Transcription

1 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 Red One 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. 2 WIF Well Integrity Workshop, May 26, 2011

3 RNNP report ed 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 3

4 RNNP report ed Ex 1 Ex 2 Ex 3 Ex 4 Ex 5 Ex 6 Ex 7 Ex 8 4

5 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 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 KV 732m MD m MD/ 1838m TVD 9 5/8" m MD/2058m TVD : failed/suspected failed barrier element PT SV HMV MMV A B C PWV X-mas tree PT PI PI DHSV 280m MD TOC 13 N/A m MD 13 3/8" shoe 1.71 sg TOC m MD/ 1848m TVD Prod packer 1.xx sg Prod 2407m MD/ 1994m TVD Seal 2438m MD 7" liner hanger 2440m MD 9 5/8" shoe N/A sg 5 WIF Well Integrity 2009 Workshop, May 28, 2009

6 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 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 KV 732m MD m MD/ 1838m TVD 9 5/8" m MD/2058m TVD : failed/suspected failed barrier element PT SV HMV MMV A B C PWV X-mas tree PT PI PI DHSV 280m MD TOC 13 N/A m MD 13 3/8" shoe 1.71 sg TOC m MD/ 1848m TVD Prod packer 1.xx sg Prod 2407m MD/ 1994m TVD Seal 2438m MD 7" liner hanger 2440m MD 9 5/8" shoe N/A sg 6 WIF Well Integrity 2009 Workshop, May 28, 2009

7 Example 1 SV KV PT PWV HMV MMV X-mas tree PT PI PI A B C DHSV 280m MD TOC 13 N/A m MD 732m MD m MD/ 1838m TVD 13 3/8" shoe 1.71 sg TOC m MD/ 1848m TVD Prod packer 1.xx sg Prod 2407m MD/ 1994m TVD Seal 2438m MD 7" liner hanger 2440m MD 9 5/8" m MD/2058m TVD 9 5/8" shoe N/A sg : failed/suspected failed barrier element 7 WIF Well Integrity 2009 Workshop, May 28, 2009

8 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 Cap Rock Primary Barriers Liner Cement Liner Hanger 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. Includes PBR (not qualified) DHSV Secondary Barriers Formation at prod packer 9-5/8 casing (above prod pkr) 9-5/8 casing cement (above prod packer) Tubing hanger/seals/plug Wellhead XMT/valves : failed/suspected failed barrier element AWV PT TOC 294m MD/ 294m TVD. See note /4"-9 5/8" 444m MD 20" 909,6m MD/ 905,4m TVD 13 3/8" 2320m MD/ 2103m TVD 9 5/8" 5465m MD/ 4318m TVD WOV AMV min 1.71 sg. MD Debris Cap ITC with plug Tbghng plug HXT extension A B C 353m MD TOC m MD/ 1769m TVD. See note 3. 3/8 shoe 1.87 sg TOC m MD/ 3643m TVD. See note m MD Horizontal x-mas tree 20 shoe 1.46 sg Prod. 5211m MD/4134m TVD 7" liner 5271m MD/ 4181m TVD 9 5/8 shoe 1.84 sg TOC 5478m MD/4325m TVD. See note 1. WIF Well Integrity Workshop, May 26, 2011 CIV1 PMV TCI THI PT XOV 5211m MD/ 4134m TVD 1.97 sg. MIV 5465m MD/ 4318m 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.

9 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 Cap Rock Primary Barriers Liner Cement Liner Hanger 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. Includes PBR (not qualified) DHSV Secondary Barriers Formation at prod packer 9-5/8 casing (above prod pkr) 9-5/8 casing cement (above prod packer) Tubing hanger/seals/plug Wellhead XMT/valves : failed/suspected failed barrier element AWV PT TOC 294m MD/ 294m TVD. See note /4"-9 5/8" 444m MD 20" 909,6m MD/ 905,4m TVD 13 3/8" 2320m MD/ 2103m TVD 9 5/8" 5465m MD/ 4318m TVD WOV AMV min 1.71 sg. MD Debris Cap ITC with plug Tbghng plug HXT extension A B C 353m MD TOC m MD/ 1769m TVD. See note 3. 3/8 shoe 1.87 sg TOC m MD/ 3643m TVD. See note m MD Horizontal x-mas tree 20 shoe 1.46 sg Prod. 5211m MD/4134m TVD 7" liner 5271m MD/ 4181m TVD 9 5/8 shoe 1.84 sg TOC 5478m MD/4325m TVD. See note 1. WIF Well Integrity Workshop, May 26, 2011 CIV1 PMV TCI THI PT XOV 5211m MD/ 4134m TVD 1.97 sg. MIV 5465m MD/ 4318m 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.

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. 10 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) 11 WIF Well Integrity 2011 Workshop, May 26

12 Example 4 Drilled and completed in 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 (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%. 12 WIF Well Integrity 2011 Workshop, May 26

13 Example 4 New values of Burst, Tension and Collapse calculated and re-modelled within WellCat to verify safety factors psi tubing re-stimulation burst safety factor identified to be lower than company safety factor of 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 s. 13 WIF Well Integrity 2011 Workshop, May 26

14 Example 4 New values of Burst, Tension and Collapse calculated and re-modelled within WellCat to verify safety factors psi tubing re-stimulation burst safety factor identified to be lower than company safety factor of 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 s. WIF Categorization 14 WIF Well Integrity 2011 Workshop, May 26

15 Example 5 Tubing to annulus leak above API acceptance criteria 15 WIF Well Integrity Workshop, May 26, 2011

16 Example 5 Tubing to annulus leak above API acceptance criteria 16 WIF Well Integrity Workshop, May 26, 2011

17 Example 6 Producer on Gas lift. Inflow test of A-annulus failed. Leak detection tool found lower GLV 2628 m md. Unable to pull GLV Plug installed below lowest 2772 m MD. Inflow tested OK. 17 WIF Well Integrity Workshop, May 26, 2011

18 Example 6 Green Well Primary Barrier: Packer Tubing below plug Inflow tested Plug Secondary Barrier: Prod casing Wellhead X-mas tree 18 WIF Well Integrity Workshop, May 26, 2011

19 Example 7 Subsea/tieback well, failed on initial production. Well was completed in September/October 1998 and attempted put on production 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 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 Small fluid leak observed from annulus B (from WH inspection port) October 2010 Small gas leak observed from annulus (HC gas) 19 WIF Well Integrity Workshop, May 26, 2011

20 Example 7 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 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 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 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

21 Example 8 SV KWV PWV 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 Primary Barrier Cemented Liner, casing Liner Top Packer Tubing above the DHSV DHSV Production packer Casing 13 3/8 csg UMV LMV X-mas tree DHSV FIT = 1,80 SG Secondary Barrier Cemented Casing, liner Wellhead Tubing Hanger Annulus Valve Xmas tree 9 5/8 csg Prod. packer 7 liner FIT = 1,88 SG FG = 2,15 SG 4 1/2 liner 21 WIF Well Integrity Workshop, May 26, 2011

22 Example 8 SV KWV PWV 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. Primary Barrier Cemented Liner, casing Liner Top Packer Tubing above the DHSV DHSV Production packer Casing 13 3/8 csg UMV LMV X-mas tree DHSV FIT = 1,80 SG Obtained a good inflow test on the DHSV Secondary Barrier Cemented Casing, liner Wellhead 9 5/8 csg Tubing Hanger Prod. packer FIT = 1,88 SG Annulus Valve 7 liner Xmas tree FG = 2,15 SG 4 1/2 liner 22 WIF Well Integrity Workshop, May 26, 2011