Well design and construction i

offshore oil and gas industry

1. 1
Well design and construction I
Adrian Adams
Nexen Petroleum UK

2. 2
Agenda
•11:00-12:00Well construction
•12:00-14:00Lunch
•14:00-14:50Well design
•14:50-15:00Coffee break
•15:00-16:00Design exercise

3. 3
Drill rigs (1): fixed (surface wellheads)
Jack-up Fixed platform

4. 4
Drill rigs (2): floating (subsea wellheads)
Semi-submersible (moored) Drillship (DP)

5. 5
Drill rigs (3): compliant platforms

6. 6
Drill rigs: water depth capability

7. 7
Rig selection
•Semi-submersibles (moored)
- exploration and development wells
- up to 3000 ft water depth for conventional mooring system
•Drillships (dynamic positioning)
- exploration and development wells
- up to 10000 ft water depth
•Jack-ups
- usually development wells (cantilever over wellhead platform)
- up to 400 ft water depth (WD)
•Platforms
- development wells only
- fixed platforms up to 500-600 ft WD, compliant above this

8. 8
Floater drilling: overview

9. 9
Rig systems: hoisting
Derrick Draw-works

10. 10
Rig systems: rotation
Kelly and rotary table Top drive

11. 11
Rig systems: circulation

12. 12
Rig systems: well control

13. 13
Well types
•Exploration
- used to look for oil and gas reservoirs
- aimed at crest of structure
- usually a throw-away well (abandon after drilling)
•Appraisal
- used to determine the extent of a discovery
- aimed at flank of structure
- may be a keeper, otherwise abandoned
•Development
- production (extract oil and/or gas)
- injection (re-pressurise reservoir by injecting water or gas)
- 10 to 20 year service life

14. 14
Well targets
Gas-Oil contact
Oil-Water contact
Seal
Reservoir Rock
Oil
Gas
Fault
Water

15. 15
Typical well schematics
80
405
0
Seabed
RT
MSL
MD BRT TVD BRT
0
80
405
64426”hole
20”shoe 642 642
396Top face guidebase 396
All depths in feet
8½”TD 11140 10590
Bottom hole location(final)
Lat: 57°48’28.300”N
Long: 00°56’14.577”W
X: 622,566.69 m E
Y: 6,409,331.61 m N
Wellhead
VetcoSG5 10000 psi
Flowbaseheading: 315.7ºG, 317.5ºT
Top face bullseyesupport beam 9 ft ASB
John Shaw
95/8”x 7”casing
9 5/8”53.5 lb/ft L80 VamTop
10ºinternal taper XO
7”29 lb/ft L80 13Cr VamTop HT
Pressure tested to 5000 psi in seawater
Surface location(slot #10) (final)
Lat: 57°48’02.377”N
Long: 00°56’23.438”W
X: 622,444.86 m E
Y: 6,408,525.68 m N
Top Buzzard SST 9652 9206
644
3695 369513 3/8”shoe
17 1/2”hole 3715 3715
9 5/8”x 7”XO 9392 8967
12¼”hole 9412 8985
TOC (theoretical)8652 8284
7”shoe 11129 10579
Revisions list
Rev 01 (20/9/06): first issue
Rev 02 (27/9/06): motor bend for 17½”hole,
13 3/8”test pressure, TD depth revised
Rev 03 (29/9/06): 13 3/8”pressure test policy
revised
Rev 04 (31/10/06): updated for as-built,
target, trajectory, and geological tolerance
revised
Rev 05 (6/12/06): updated for as-built
30”x 20”conductor
30”x 1.5”X52 extension BWP up x HD/HT-90
30”x 1.5”X52 XO HD/HT-90 x SF-60
3 jts30”x 1”X52 SF-60
20”133 lb/ft X56 shoe joint c/wXO to 30”SF-60
Final bullseyereadings 0.5ºforward, 0.5ºaft
Hard cement tagged 20 ft BSB (both funnels),
40 bbl top-up both sides
133/8”casing
18¾”HP housing c/w21”x 1.25”extension
20”x 13 3/8”XO joint
13 3/8”72 lb/ft L80 VamTop
Pressure tested to 1800 psion bump
Pressure test to3000 psiafter BOPsset
BJ Lite115
330 bbl 12.5 ppg(250% excess)
62436”hole 624
CCB Class G
Lead 930 bbl 13.2 ppg(150% excess)
Tail 90 bbl 16.0 ppg(15% excess)
CCB Class G
Tail 105 bbl 16.0 ppg (10%)
87
457
0
Seabed
RT
MSL
MD BRT TVD BRT
0
87
457
20”shoe
26”hole 697 697
36”hole 677 677
3478 3478
LiteFIL RHC
408 bbl
12.5 ppg
449Top face LP housing 449
All depths in feet
Rugby class G
Lead 838 bbl 12.5 ppg
Tail 167 bbl 16.0 ppg
TOT 2978 2978
12¼”TD 9179 9179
12¼”coring
Core Burns sandstone on shows
Logging
As per logging programme
Bottom hole location
Lat: 57°39’03.830”N
Long: 00°52’44.929”W
X: 626,573.00 m E
Y: 6,391,987.00 m N
Wellhead
Vetco SG5 10M
133/8”casing
Pre-assembled 18¾”WHH assembly
Seat protector, SSR and top wiper plug pre-installed
Approx 74 joints 133/8”72 lb/ft L80 BTC
Pressure test on bump to 2000 psi
12¼”hole
Smith MA74PX, PDM/ABH 0.78 deg
DIR/INC/GR/RES/SONIC
Drill out wiper plug with seawater
Displace to 10.0 ppgWBM while drilling cement
Drill 10 ft new hole, circulate and condition mud
Perform FIT to 15.0 ppgminimum
Increase MW to 11.5 ppgbefore bottom Chalk
Drill ahead 12¼”hole to TD
17½”hole
Smith MG02TQc, PDM/ABH 0 deg
DIR/INC/GR
Seawater + high-vissweeps (8.7 ppg)
10.5 ppgdisplacement mud
30”x 20”conductor
30”x 1.5”X52 extension BWP up x HD/HT-90 b/d
30”x 1.5”X52 XO HD/HT-90 p/u x SF-60 b/d
3 jts 30”x 1”X52 SF-60 pin up x box down
20”133 lb/ft X56 shoe joint c/wXO to 30”SF-60 p/u
36”x 26”hole
26”MSDSSHc+ 6-point HO, PDM/ABH 0 deg
DIR/INC
Seawater + high-vis sweeps (8.7 ppg)
10.0 ppg displacement mud
BOP
Hydril 18¾”15M
C
h
R
d
R
d
C
h
A
h
A
l
Abandonment(indicative)
5 x 600 ft plugs on bottom
2 x 500 ft plugs across shoe
Tag and test shoe plug
Final plugs dependent on formations
Sedco 714
95/8”casing
Contingency for hole problems or DST
9 5/8”47 lb/ft L80 New Vamavailable
Surface location
Lat: 57°39’03.830”N
Long: 00°52’44.929”W
X: 626,573.00 m E
Y: 6,391,987.00 m N
133/8”shoe
Run BOP
Run and test BOP to 5000 psi
Top Burns 6504 6504
692
17½”hole 3498 3498

16. 16
Casing strings
36 inch
Hole
30 inch
Conductor
26 inch
Hole
20 inch
Casing
17
1
/2
inch
Hole
13
3/8
inch
Casing
12
1
/4 inch
Hole
9
5/8 inch
Casing
8
1
/2 inch
Hole
7 inch
Liner
6 inch
Hole
5 inch
Liner
Typical casing design for central North Sea

•Conductor (30” diameter, 36” for deep water)
- supports weight of inner strings
- cases off soft topsoils
- usually 6 no. 40 ft joints (240 ft)
•Intermediate casing (usually 13 3/8”)
- cases off Tertiary formations
- usually set in top UC Chalk (3500-4000 ft)
•Production casing (usually 9 5/8”)
- cases off Chalks and LC Siltstones
- usually set just above reservoir
•Liner (usually 5½” or 7” diameter)
- set across reservoir
•NB: optimum casing design varies by area
(depths, geology, drilling hazards)

17. 17
Typical lithology (central North Sea)

18. 18
Casing cementation
•Cement is pumped down
the well between the top
and bottom plugs
•Once bottom plug bumps,
cement is expelled through
float valve and up the
annulus (i.e., outside the
casing)
•The cement volume is
disposed such that top of
cement (TOC) is at the
desired height once the top
plug bumps
•TOC height is determined
by zonal isolation
requirements
•Once the cement has set,
the plugs, float and shoe
track are drilled out
Displacement
Fluid
Top Plug
Cement
Slurry
Centralizer
Centralizer
Bottom Plug
Float Valve
Open
Casing
Shoe
Float Valve
Closed
Top Plug
Seated
Displacement
Fluid
Drill Bit
Drillstring
Stabilizer
Stabilizer

19. 19
Drilling fluids
Functions of drilling fluid
•Provides primary well control
•Stabilises open hole (mechanical, chemical)
•Cools and lubricates bit
•Removes cuttings from bit
•Transports cuttings to surface
•Powers the mud motor
•Reduces torque, drag (run/pull DP, casing)
•Provides fluid medium for well logging
Types of drilling fluid
•Seawater plus hi-vis sweeps
•Water based mud (WBM)
•Oil based mud (OBM)

20. 20
Drilling fluid selection (central North Sea)
•36” section (30” conductor)
- seawater plus hi-vis sweeps
- displace to 10.5 ppg bentonite WBM after drilling
•17½” section (13 3/8” casing)
- seawater plus hi-vis sweeps
- displace to 10.5 ppg bentonite WBM after drilling
- reactive shales may limit shoe depth
•12¼” section (9 5/8” casing)
- WBM if reactive shales not a problem, OBM otherwise
•8½” section (7” or 5½” liner)
- as 12¼”, but drill-in (clear) fluid if risk of formation damage

21. 21
Drill bits
Mill tooth TCI PDC
Tungsten carbide Polycrystalline
insert diamond compact

22. 22
Drill bit selection
•Mill tooth bits
- can only drill soft formations: Quaternary, top Tertiary
- used for tophole (36” section: 26” bit plus 36” hole opener)
•TCI (or “insert”) bits
- can drill all formations, including chert and pyrite
- rate of penetration (ROP) ±10 ft/hr in hard formations
- life limited by bearing wear (750 krevs, 24-36 hours drilling)
- used for 17½” section if chert at Ekofisk/Tor transition
•PDC bits
- can drill up to moderately hard formations (not chert and pyrite)
- ROP 10-100 ft/hr, depending on formation
- life limited by cutter wear (3-5 days if bit correctly chosen)

23. 23
Bottom-hole assemblies (1)
•Essential
- heavyweight DP, drill collarWeight on bit
- drilling jars and acceleratorJar stuck pipe
- non-magnetic DC Allows azimuth measurement
- MWD (instrumentation) Inclination, azimuth, GR
- MWD (telemetry) Real time D&I / GR
- stabilisers Directional control
•Optional
- motor ROP improvement
- AGS / ABH motor / RSS Steering
- LWD (logging while drilling)GR, sonic, resistivity, DN
- PWD (pressure while drilling)BH pressure
- drillstring mechanics Vibration control

24. 24
Bottom-hole assemblies (2)

25. 25
Drilling problems (1)
•Kick: oil or gas flowing into wellbore. Close BOP, circulate out kick
to mud-gas separator via choke and kill lines. If not controlled,
may develop into:
•Blowout: an uncontrolled release of oil or gas, either underground
(between permeable zones), or to surface
•Lost circulation: mud flowing out of well into formation, usually
because LOP has been exceeded. Reduce flow rate, and hence
BH pressure. If still losing, pump LCM (loss control material) pill.
•Stuck pipe: DP or casing stuck in well, either mechanically (key-
seating) or differentially (mud weight too high with respect to
formation pressure, pipe pushed against hole wall)
•Parted or twisted-off BHA: fish lost-in-hole assembly. If
unsuccessful, cement fish into place, sidetrack well, and redrill lost
section.

26. 26
Drilling problems (2)

27. 27
Well evaluation (1): wireline logging
Determine:
•Presence and nature of hydrocarbons
•Formation properties (porosity, permeability)

28. 28
Wireline / e-line log types
Open hole
•GR, sonic, resistivity, DN Reservoir porosity, permeability
•VSP (vertical seismic profiling)Hydrocarbons below hole TD
•RCI pressures Reservoir pressure(s)
•RCI samples Hydrocarbon (HC) samples
•SWC (percussion side wall core)Reservoir rock samples
•RCOR (rotary side wall core) Reservoir rock samples
Cased hole
•CCL / drift Casing connection depths
•PLT (flow rate only) Bottom-hole flow rates
•PLT (samples) Bottom-hole HC samples
•SBT, USIT Cement job competence

29. 29
Well evaluation (2): coring
Determine:
•Formation properties
(porosity, permeability)
•Measured from
recovered sample

30. 30
Well evaluation (3): testing
•Determine flow rate
•Acquire samples under flowing conditions
•Infer reservoir volume
•Assess reservoir connectivity

31. 31
Completion
Packer
Tubing Hanger
c/w 6.187” QN
Safety Valve c/w
5.980” QN
7” 29 Lbs/ft Tubing
Nipple c/w
5.875” QN
Packer
Nipple c/w
5.750” QN
Depth Correlation
Sub (DCS)
7” 29lb/ft Liner
DCS DCS
Tubing
connections

32. 32
Construction sequence
Typical exploration well
•Tow to location, run anchors
•Drill 36” hole section
•Run and cement 30” conductor
•Drill 17½” hole section
•Run and cement 13 3/8” casing
•Run BOPs and marine riser
•Drill 12¼” hole section
•Log well on wireline
•Abandon well (set cement plugs)
•Pull BOPs and marine riser
•Cut and pull 13 3/8” x 30”
•Pull anchors
Typical development well
•Tow to location, run anchors
•Drill 36” hole section
•Run and cement 30” conductor
•Drill 17½” hole section
•Run and cement 13 3/8” casing
•Run BOPs and marine riser
•Drill 12¼” hole section
•Run and cement 9 5/8” casing
•Drill 8½” hole section (reservoir)
•Log well on wireline
•Run 7” liner
•Clean-up well, displace to brine
•Run Xmas tree and completion
•Pull BOPs and marine riser
•Pull anchors