1. KUNNE BEDRE KOMPETANSE AVVERGET
MACONDO-ULYKKEN I MEXICO-GULFEN?
Svein Olav Drangeid
Vice President HSE & Risk Management

2. DEEPWATER HORIZON
A DEEP WATER “WORKHORSE”
• Owned by Transocean
• Built in 2001 by Hyundai Heavy Industries
Shipyard, Ulsan, South Korea
• Design: Reading & Bates Falcon RBS-8D
• 5th generation Semi, 15,000psi RWP DP rig
• Capable of working in up to 8,000 ft WD
• Held Industry’s MODU well depth record of
31,000 ft. in 4000 ft WD
• Had been on contract with BP since delivery
Source: Transocean 2

3. THE WELL PROJECT – MACONDO #1
• First exploration well on the Macondo prospect in 5067 ft of water
• Planned well TD @ 20,600 ft (Deepwater Horizon world record = 31,000 ft)
• Spud Macondo Oct. 6, 2009 with rig “Marianas” (AFE 77 days, target 52 days)
• Abandoned well after BOP problems and Hurricane “Ida” Nov 9, 2009
• Re-entered with “Deepwater Horizon” Feb 2010 (Day rate $533.496)
• TD the well @ 18,360 ft, i.e. 2,240 ft shallow not reaching the 2nd target
• The well proved to be a big discovery
– It was decided to change the objective of the well to be a producer, and to abandon the
well temporary.
– Then re-enter well for completion with another rig (Deepwater Horizon was long overdue
and expected on another well)
3

4. Csg. Size Depths (m)
EVENTS IN THE WELL: Mudline 1544
36” cond. 77 1620
• Hole Problems in 18 1/8”x 22”UR hole; TD
Section 1000’ high
28” cond. (adpt.) 350 1890
• BOP Problems – had to pull to surface
• Hurricane ”Ida”, had to leave site and repair 22” csg.(BOP) 875 2420
the Marianas rig
• Re-entered the well with DH (more expensive) 18” liner (adpt.) 1190 2735
rig 3 months later
• Kick, lost circ. in 16 ½”x20” UR hole, had to set
16” high 16” csg. (adpt.) 1987 3533
• Hole instability, stuck pipe, cut free/lost BHA &
sidetrack 13 5/8” liner 2463 4009
• Ran Liner on top of reservoir !!!!!!
• Heavy mud losses in the reservoir section (lost 11 7/8” liner 3060 4606
3000 bbls of SOBM)
• Did not make it to TD and secondary well
target 9 7/8” liner 3690 5236
7” x 9 7/8” 4054 5560
Reservoir
4

5. CASING OFF FORMATIONS
Normal casing programs
consists of:
• Long strings, hung off in
the wellhead,
• Production casing
installed on top of
reservoir
• Production liners, hung
off in the previous casing
string
5

6. BOP
WELL BARRIERS
• Barriers against bottom hole
pressures while drilling: Seabed
1. First line of defense – the
PRIMARY barrier:
Drilling fluid in hydrostatic
overbalance (blue),
maintained by circulation
2. Second line of defense – the
SECONDARY barrier:
Pressure tight envelope
consisting of barrier elements
which have been installed
and leak tested to withstand
the well bore pressures (red)
Reservoir
6

7. DIFFERENCE BETWEEN LONG CASING AND LINER
Liner Casing
• • From a barrier point of view the
long casing is fully reliant on a
successful primary cement
operation
– which in itself is a contradiction
(since it is more challenging)!
• Especially in the case of
Macondo with a weak formation
to seal off, every effort should Plug
be made to ensure that primary
cementing of the reservoir
casing should be successful
• In the liner case there are
several and more robust
barriers, and an improved
situation for a successful ”Highway
cement job to hell”
Reservoi r
7

8. CEMENTING CASING
Critical Factors:
• Centralization
• Mud Removal / Pump
rate
• Channelling
• Bonding
• Volume
• Back-pressure
Reservoir
Animation
8

9. INSUFFICIENT PRE-CEMENTING CIRCULATION
• Insufficient pre-cementing circulation to clean the annulus
– Fear of loosing the “LCM barrier”
– Used far too low pump rate
– Did not completely circulate “bottoms up”
• Risks
– Hydrocarbons may still be
trapped in mud
– Inadequately conditioned
mud (gel-effect)
9

10. INADEQUATE CENTRALIZATION
• Halliburton’s Simulation:
– 21 Centralizers needed
• BP’s Decision:
– Cement with 6 Centralizers
Which were all they had on
board……. !!!
10

11. WHAT WAS THE FOCUS WHEN
CEMENTING ???
• Weak Formation Issues was still their main concern
Hence………..
• Too low pump rate is applied
– Risk of not achieving proper mud removal
– Risk of not achieving proper cement placement
• Cement slurry density is too low
– Insufficient back pressure on casing floats
– Which again Risk of Cement flowing back into casing 11

12. MORE CEMENT PROPERTIES ISSUES……
• Foam cementing deep in an HP well is unusual and
nothing BP had done before
– Risk of nitrogen break out, etc.
– Necessary to avoid loss to formation if the cement is too heavy
• Insufficient pre-testing/ cement simulations of recipe
– No laboratory tests of the actual recipe
– Additional retarder and nitrogen foam added after original
tests
– Nobody really knew how long the cement needed to cure
12

13. CEMENT BARRIER INSUFFICIENTLY VERIFIED
• The result of the cement job was based entirely on
observations during the cementing operation
– (Measure of returns volume)
• No Casing Bond Log (CBL) were run
• No Top of Cement Log (TOC) were run
All to save a few hours………
• Schlumberger loggers were in fact de-mobilized
13

14. PRE-MATURELY WORKED ON CASING
• After 10 hours the casing was pressure tested to 2500 psi
for 30 minutes.
– Test OK (but 24 before cement setting)
– Risk for creating a micro annulus!
– Risk of squeezing the cement out and into the formation
NB: Cement simulations had shown that after 24 hours the cement
slurry had built no strength.
Only after 48 hours it had built a shear strength of 1590 psi
• Tripped in hole with workstring to 8367 ft, already 16-18
hours after pumping cement
– Far too early according to lab test of cement recipe
– Started displacing mud out of the hole by sea water
14

15. The Root Cause…?
15

16. COMMON TYPE FAILURES IN
ACCIDENT SCENARIOS…
• Basic design and engineering mistakes
– Questionable casing program, causing cementing short cuts to be made and creating a leak
path straight to surface
• Lack of proper “Management of Change” - major changes under way in the
project:
– Change of rig, crew and contractors
– Change of well objective from exploration to producer
• Lack of risk identification and understanding
– Neither consequence of unsuccessful results of decisions made were documented, nor what
risk mitigation that was taken (during negative pressure test and converting of float)
• Absence of basic well control procedures and control
– Well and volume control in critical phases of the well
• Not giving safety the highest priority (Walk the talk!)
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17. STRATEGIC AND ORGANIZATIONAL
CIRCUMSTANCES
1. The way the activity of planning and executing the activity is
resourced, organized, structured and managed
(Organizational unit, Teams, Rigs and Contractors, Manning
level, Competency assurance and financial support)
2. How the work is carried out
(Mgt. guidelines, goals, HSE culture, process, procedures, preparations
& planning)
3. How the work is supervised and quality controlled
(peer reviews, independent verification, expectations, follow up/ “walk
the talk”)
4. The way the work program is implemented offshore - routines and
processes (internal control, respect for procedures/ instructions, stop
work authority, etc.)
5. The way that individual competence is utilized
(open and honest communication or management by fear?)
Communicate/ discuss hazards and share important information.
17

18. THE ROOT CAUSE…?
• Deep water casing design and drilling methods
(need to use Dual Gradient Drilling, dry BOP or other means to be able to drill
longer hole sections?)
• Complacency and attitude, failure to acknowledge the inherent
risks of the activity when it becomes “routine”
• Time, Cost and Schedule focus – insufficient risk management
• Safety Culture (may vary within the company/ different parts of the World)
• Best Practices and Best Available Technology was available but
not applied
• Failure of the regulatory environment to correct matters
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19. PASSIONATE
PARTNER
Maximising Potential
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