NORSOK D-010 Well integrity in drilling and well operations

Rev. no.4 (June 2013)

What is really new?

Presented at WIF Workshop, Sandnes, 4.6.13

Terje Løkke-Sørensen

Well Engineering Manager

add energy

Milestones

Comments – round 1 (24.08.11)

Kick-off meeting (26.10.11)

Comments – round 2 (15.11.11)

Mini-hearing EGD/DMF (15.8.12)

EGD meeting (12.12.12.)

Industry Hearing (20.12.2012)

Receive comments (15.2.13)

Submit section draft for QA (12.4.13)

All sections completed (14.5.13)

Compiled draft submitted (27.5.13)

Approved by EGD (27.5.13)

Approved by Standard Norge (30.5.13)

Issue on webb (June 13)

Reflection: Why should it take almost 2 years to revise a standard?

Comments received

Company No.

Statoil 441

BP 367

Shell 125

BG 118

COP 102

PSA 89

TENAS 71

Esso 68

Total 58

Marathon 53

Maersk 43

Petrobras 43

PGNIG 43

SLB 39

Lundin 31

Woodside 26

AGR 20

Other (<20) 80

Sum 1817

Comments

15.1

1.2

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20.1

2.1

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)

To

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1. Scope 1 4 0 5

2. Normative & Informative Ref. 1 8 0 9

3. Definitions and Abbreviations 38 7 147 192

4. General Principles 112 50 325 487

5. Drilling Activities 43 28 373 444

6. Testing Activities 16 3 99 118

7. Completion Activities 11 45 237 293

8. Production Activities 12 25 143 180

9. ST, Susp. & Aban. Activities 40 26 256 322

10. Wireline Operations 11 2 84 97

11. Coiled Tubing Operations 4 0 30 34

12. Snubbing Operations 5 0 26 31

13. Under Balanced D&C Ops. 3 2 60 65

14. Pumping Operations 3 0 37 40

Annex A 4 0 0 4

1. Correct english language

304 200 1817 2321

20.12.12

Reflection: Why does people always wait till the last minute ?

Estimated total work hours

Estimate of work hrs per. 30.05.2013

Activity Units hrs/unit Sub-total (hrs)

Project Leader 925

Editor / EGD / PSA meetings 903

Section review 16 50 800

Special topic meetings 32 16 512

Initial comments 305 1 305

PIF comments 3 50 150

PAF comments 3 50 150

Mini-hearing (DMF) 200 1 200

Hearing (20.12.12) 1817 1 1817

TOTAL EST. 5762

DONE

Reflection: How much time has those who provided the comments spent ?

+/- 6000 hrs

Reflection: Was it worth it?

Macondo Norsk Olje & Gass issued a report with specific recommendations of what should be revised in D-010

-> these were tracked separately and published in the industry hearing

Main changes

• Rev.3 normative references has become informative references

• WBS are demoted to EXAMPLES only

• Common WBE requirements moved to EACs

• 9 new EACs

• Harmonized with : – D-001 Drilling Facilities – D-002 Well Intervention Equipment – D-007 Well Testing

• Recommendations from Norsk Olje og Gass’ Macondo report is included

Potential for increased cost

• Kill with (1) relief well -> more casing strings?

• 2 barriers to prevent escape of gaslift gas -> ASV in subsea well?

• Logging of critical cement, tagging & drilling of cement plugs -> more time?

• Formation integrity -> deeper plugs?

• Injection rate pressure < cap rock fracture pressure -> reduced injection rates?

4. General

+ How to make WBS

+ Inflow testing

+ Formation testing and acceptance

+ 1+(1) relief well(s), cont. plan & well capping eq.

+ Well design pressure, design principles &factors

+ Structural integrity

+ Personnel training

+ WI management system

- Removed: Well program content, reporting of well control incident to PSA

5. Drilling activities

+ Casing hanger lock-down capabilities

+ Risk analysis, procedures and training to centralize pipe prior to closing shear rams

+ The surface casing shall be installed before drilling into an abnormal pressured zone.

+ Well control action procedures and drills expanded with new scenarios.

+ Relief well & PA should be addressed in casing design

+ Conductor design

+ Potential for shallow gas well if no relevant offset well exists

2 casing float valves – autofill OK no sources of inflow exposed.

- Model for minimum separation between wellbores replaced with generic requirement

Annex A is updated.

BOP testing frequency unchanged!

6. Well testing activities

+ Able to close two sets of BOP rams on slick joint (sub sea wells)

+ Evacuated test string load case

+ UB annulus fluid wells; Inflow test values should include a safety margin

+ SST able to cut wire / CT

+ UB annulus fluid wells; Use of retrievable packer OK - pressure test packer from below

- Removed «HPHT Well testing» section

- Well Test string equipment -> D-007

- Surface flow lines /connections -> D-007

7. Completion activities

+ XT, DHSV & packer in all wells with HC / flow pot.

+ Monitoring of production bore, A&B annulus all wells. Pressure gauge on all accessible annuli.

+ 2 more WC action procedures (sand screens, anchoring failure) and 2 more WC drills (kick drill RIH completion and emergency disconnect)

+ All gas lift wells shall have two barriers to prevent release of the A-annulus gas volume

+ All platform wells shall have a ASV

+ ASV can be replaced by GLV

+ CAL IV connection for tubing exposed to gas

+ Injected media to be contained within the targeted formation zone (reservoir) without risk of out of zone injection. Requirements to logging and packer location.

X

8. Production activities

+ All wells to have an updated WBS

+ Wells shall be well integrity categorized as per GL 117

+ Handover of well documentation

+ How to react to anomalies -> evaluate, risk assess, MOC

+ Casing & tubing annuli pressure operating range

+ Safety critical valve failure rates exceeding 2% /12 month period -> root cause analysis -> actions to reduce the failure rate.

9. Abandonment activities

+ Simplify by use of examples to support text

+ Re-defined Suspension to only include wells under construction, Temporary Abandonment,- with monitoring (in-definite) and without monitoring (max. 3 years)

+ Examples on placement of plugs/casing cement (permanent P&A)

+ Relevant EAC tables have been edited where necessary

+ Decision support for section milling and placement of cement behind casing

+ Cement plug verification – tag or drill

+ XMT removal requirements added

10. Wireline operations

+ Risk analysis focus - two additional sections with discussion on reducing probability and consequences of compromised WBE

+ Riserless Light WI:

– New section summarising minimum vertical bore elements in well control stack

– New WBS example

– New EACs (x3 following Statoil structure)

+ Toolstring deployment:

– New section outlining some alternative deployment options

– New WBS example for bar deployment

13. MPD/UBD operations

+ Added Managed Pressure Drilling (MPD) for platforms – does not exclude subsea operations.

+ Introduced well control action matrices for MPD and UBD.

+ Introduced ” Additional Common WBE Criteria” in EAC tables: 2 (Casing), 4 (Drilling BOP), 5 (Wellhead), 22 (Casing Cement), and 26 (High Pressure Riser)

+ New WBS: MPD

+ Table 53: UBD/MPD choke system

+ Table 54: Statically Underbalanced Fluid column

+ RCD shall be qualified as per API 16RCD

The other sections

11. Coiled tubing operations

12. Snubbing operations

14. Pumping operations

-> only some minor changes

15. Well Barrier Elements EAC + Table 50 – In-situ formation

+ Table 51 – Creeping formation

+ Table 52 – UBD/MPD choke system

+ Table 53 – Statically underbalanced fluid column

+ Table 54 – Material plug

+ Table 55 – Casing bonding material

+ Table 56 – Riserless Light Well Intervention – Well Control Package (WCP)

+ Table 57 - Riserless Light Well Intervention – Lower Lubricator Section (LLS)

+ Table 58 – Riserless Light Well Intervention – Upper Lubricator Section (ULS)

15.12 Casing Cement Acceptance criteria

Actual cement length shall be:

• above potential source of inflow/ reservoir

• 50 m MD verified by displacement calculations or 30 m MD when verified by bonding logs. Formation integrity shall exceed the maximum expected pressure at base of interval.

• 2 x 30m MD verified by bonding logs when the same casing cement will be a part of the primary and secondary well barrier.

• Formation integrity shall exceed the maximum expected pressure at the base of each interval.

• Injection pressure exceeding formation integrity at cap rock: Cemented from injection point to 30 m MD above top reservoir verified by bonding logs.

Verification method

The cement length shall be verified by one of the following:

1. Bonding logs: Fit for purpose, azimuthal /segmented data, verified by qualified personnel

2. 100 % displacement efficiency . Actual displacement pressure/volumes vs. simulations Losses, -> loss zone to be above planned TOC (ref. similar loss case(s) -> sufficient length verified by logging.)

3. Losses: PIT/FIT or LOT is OK only for drilling the next hole section.

24. Cement plug

Verification:

Cased hole plugs tested either in the direction of flow or from above.

Shoe track: bleed back volume = calculated volume; pressure tested + supported by overbalanced fluid or inflow tested.

Check surface samples + cure at downhole temp.& pressure.

Installation verified through evaluation of job execution

Plug in open hole: Tag (no pressure test)

Plug in cased hole: Tag + pressure test to 70 bar above LOT below casing/ potential leak path, or 35 bar for surface casing plugs. Exemption: If set on a pressure tested foundation, no pressure test is not required -> verify by tagging.

If one continuous cement plug (same cement operation) is a common WBE, it shall be verified by drilling out until hard cement is confirmed.

Open hole Cased hole

In surface

casing

100 m MD, min. 50 m

MD above source of

inflow/leakage point. In

transition from open

hole to casing should

be min. 50 m MD

above and below

casing shoe.

50 m MD if set

on a

mechanical/

cement plug

as foundation,

otherwise 100

m MD

50 m MD if set

on a

mechanical

plug,

otherwise 100

m MD.

A standard is worth nothing unless it is referred to!

Knut Heiren, Standard Norge, 2004