burlington resources dea q4 2003 presentation
DESCRIPTION
drilling low cost wellsTRANSCRIPT
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vision
people
assets
community
Reducing Well Costs MLN Field, Algeria
Neal Whatson
Burlington Resources Algeria LLC
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2
The Location
Burlington resources operates the MLN field in block 405 in theBerkine basin, Algeria. The field lies 280 km SE of the nearest
support facilities located in Hassi Messaoud.
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3
Algeria - Block 405a
Block 405
Hassi Messaoud
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4
Background
• Burlington Resources acquired block 405 from LL&E in 1997
• At that time 8 wells had been drilled. These were large bore vertical wells taking 80+ days
• One rig operation drilling 5 to 8 wells / year
• Problems operating in Algeria include:
– Algerian oil ministry policies & regulations can be ambiguous and difficult to corroborate
– The security issues associated with operating in Algeria elevate well costs
– New and evolving technology not always readily available and canbe expensive to introduce
– Provision of services is relatively expensive in comparison to NS
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Burlington’s Original Goals
1. Optimise well design
– Identify ways in which the conceptual design of the wells can be altered without compromising the well objectives
2. Continue to improve performance in all areas of operation
– Demonstrate that a continuous learning process is in place and further enhanced
– Establish well performance goals and targets
– Capture lessons learned from previous wells
– Provide specific evidence of where lessons learnt have derived performance improvements
3. Benchmark performance
– Verify performance and monitor improvement against other operators by participating in a industry recognized benchmarking process
– Be one of the top three operators in Algeria for overall performance
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The Impact
0
500
1000
1500
2000
2500
3000
3500
4000
0 10 20 30 40 50 60 70
DAYS
DPE
TH (m
)
MLN-5 MLN-6 KMD 1 KMD-2
DEC 1998
MARCH 1999
AUG 2001
Nov 2002
18.4 days to TD
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1. Well Design
• Aim was to optimise well design without compromising well objectives
• Established that 4 ½” tubing size was optimal for MLN production
• Dual completions were not an option for MLN as both reservoirs were insufficiently developed in the same areas
• Well design could therefore be modified from large to slim bore to reduce drilling times and costs
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Reduced Well Bore36" HOLE
30" CASINGX-42, 1.5" WT ST-2
30" Shoe @ 70 m
T.O.C @ 150 m
26" HOLE18-5/8" CASINGK-55, 87.5 lb/ft, BTC
18-5/8" Shoe @ 500 m
DV COLLAR 13-3/8" CSG @ 1,400 m
16" HOLE13-3/8" CASINGK-55 72 lb/ft BTC T.O.C @ 2,430 m
13-3/8" Shoe @ 2630 m
12-1/4" HOLE9-5/8" CASINGP110, 53.5 lb/ft, New Vam T.O.L @ 3030 m
9-5/8" Shoe @ 3180 m
7" LINERP-110, 29 lb/ft, HSC
7" Shoe @ 3700 m
Aquifers
Over-pressured Brine
Tag-I Reservoir Sands
F1a Reservoir Sands
24" HOLE18-5/8" CASINGK-55, 87.5 lb/ft BTC
18-5/8" Shoe @ 70 m
T.O.C @ 150 m
16" HOLE13-3/8" CASINGK-55 54.5 lb/ft, BTC
13-3/8" Shoe @ 500 m
9 5/8" DV collar removed. Lite w eight cement
12-1/4" HOLE9-5/8" CASINGN-80, 43.5 lb/ft, BTC T.O.C @ 2,430 m
9-5/8" Shoe @ 2630 m
8-1/2" HOLE7" CASINGP-110, 29 lb/ft, HSC T.O.L @ 3030 m
7" Shoe @ 3180 m
4-1/2" LINERSM13CrS95, 12.6 lb/ft, NVam
4-1/2" Shoe @ 3700 m
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Evolution of Completion DesignTRSCSSV
3-1/2" 9.20#, N-80 New VAM Tubing327 joints
0 0 0
Retreivable Packer
Cross-over, 5" x 3-1/2"2.75" 'XN' Profile Nipple Perforated Jt. 0 o 0
o oo
2.562" 'RN' Profile Nipple
Tubing Mule Shoe (Bottom)
PBTD @ 3,735 m
Sliding Side Door
Jt. 3-1/2" Tubing
XO, 4-1/2" NV (Pin) x FOX (Pin)2 Jts 4-1/2" NV tubingPup Jt. 4-1/2" NV
SSSV, Mod. 13Crw/ 3.81" BR Nipple Profile
4-1/2" 12.6 lb/ft, S13Cr Tubing
Pup Jt. 4-1/2" NV
3.75" 'AF' Nipple, Mod. Cr 13Pup Jt. 4-1/2" NVK-22 Anchor Latch, Cr 13
Millout Extension, 5" x 5', Mod. Cr 13X-over, 5" NV (Box) x 4-1/2" NV (Pin)3.75" 'AR' Nipple, Mod. Cr 13
Tie Back Seal Assy.
Pup Jt. 4-1/2" NV
Production Packer, model 85 SABL-3 47# x 3.8, Mod. 13Cr
TBSA Mule Shoe (bottom)
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Future Completion DesignXO, 4-1/2" NV (Pin) x FOX (Pin)2 Jts 4-1/2" NV tubingPup Jt. 4-1/2" NV
SSSV, Mod. 13Crw/ 3.81" BR Nipple Profile
4-1/2" 12.6 lb/ft, S13Cr Tubing
Pup Jt. 4-1/2" NV
Pup Jt. 4-1/2" NV
XO, 4-1/2" NV (Pin) x FOX (Pin)2 Jts 4-1/2" NV tubingPup Jt. 4-1/2" NV
SSSV, Mod. 13Crw/ 3.81" BR Nipple Profile
4-1/2" 12.6 lb/ft, S13Cr Tubing
Pup Jt. 4-1/2" NV
Tie Back Seal Assy.
Pup Jt. 4-1/2" NV
TBSA Mule Shoe (bottom)
?
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2. Drilling Optimisation
• Optimise the drilling processes
• Establish achievable but challenging targets and continually raise these as performance improves
• Identify and prioritise areas with the highest potential for time and cost savings
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Continually Raise the Target
MLN
-6
MLN
W-1
MLC
-2
MLS
E-3
MLN
W-2
MLS
E-4
MLW
-2
MLN
W-4 MLN
W-3
ZTH
-1 MLW
-3
MLS
E-1
MLW
-1 MLS
E-2
MLN
-5
MLC
-1
MLS
-1
MLN
-7
MLN
-8
MLS
E-6
KMD
1
MLS
E 7
KM
D-2
MLN
W-5
MLS
E-5
MLN
9
MLN
W 6
MLN
10
-
50
100
150
200
250
0 5 10 15 20 25 30
M/D
AY
Actual TL AVRG Targets Series15 Series16
TARGET 1999
TARGET 2000TARGET 2001
164 m / d
63M/D ave
103M/D ave
122M/D ave128M/D ave
126M/D
152M/D
169M/D
NOTE - MLN 9 WAS A DIRECTIONAL WELL TAKE
CORRECTED FOR STRAIGHT HOLE WOULD
HAVE GIVEN US 158 M/D
TARGET 2002
170M/D ave
189m/d
212M/D
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Technical Limit
Well ‘target curve’ generated by
incorporating the best ever
performance for each
individual section
As performance improved, the
‘technical limit’ improved.
This resulted in a continual moving
goal for the team to aim for
KMD-2 Time Depth Curve
18 5/8in Casing 76m
13 3/8in Casing 424m
9 5/8in Casing 2545m
Cut Tag-I Core TD 3387m
7in Casing 3120m
0
500
1000
1500
2000
2500
3000
35000 5 10 15 20 25 30 35
Days
Dep
th (m
)
KMD-2 Days Planned (AFE) KMD-2 Actual Days Technical Limit by Interval
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12 ¼” Section
• The slim bore design placed the 13 3/8” shoe at 450m, and the 12¼” section TD 2,500m
• This section has highly interbedded formations with soft clastics, salts, dolomites, abrasive sandstones and hard anhydrite stringers
• Typically took three bit runs to complete
• This section identified as having the greatest potential for time and cost savings
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Partnership With Oasis
• BR Well Operations team identified that undertaking a systematicdrilling performance initiative could yield significant efficiency and cost saving benefits
• As part of that initiative, BR contracted the drilling optimisation service Baker Hughes Oasis
• The drilling challenge was to increase penetration rates, preserve borehole stability, reduce the number of bits and lower overall drilling costs
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Initial Performance
• Situation in July 1999
• MLN-6
• MLNW-1
• Even with a dedicated clean out run two bit runs were required
Size Type TFA / Jets
Depth In Depth Out
Metres Bit Hrs Ave. ROP
12 ¼ FM2943T 8 x 11 405 1656 1251 38 32.9 12 ¼ FM2943T 8 x 11 1656 1913 257 15.7 16.4 12 ¼ DS113HGN 7x11,1x12 1913 2521 608 70 8.7
Size Type TFA / Jets
Depth In Depth Out
Metres Bit Hrs Ave. ROP
12 ¼ GTXG3 OPEN 468 473 5 0.5 10.0 12 ¼ DS113HGN 4x10,4x11 473 2249 1776 78.3 22.7 12 ¼ M68P 4x13,4x10 2249 2644 395 47.0 8.4
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The Process
• Continual improvement process
– Planning, execution, post well analysis, knowledge capture
• Pre well optimisation study
– A detailed study identified operations where improvement could be achieved. Offset log data and analysis of rock mechanics helped define in-situ rock drilling properties. A detailed set of hole section drilling guidelines formation by formation was produced
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The Process
• Drilling implementation
– The rig site team ensured full implementation of the well plan
– A drilling optimisation engineer (DOE) was stationed on the rig floor throughout drilling to focus input from all rig disciplines – geologists, mud engineers, mud loggers and bit engineers
– Rig site awareness campaigns ensured recommended practices were followed
• Post well evaluation and knowledge capture
– A critical post well evaluation captured lessons that were then incorporated into the next pre-drill study
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The Incentive
• The drilling of MLC-2 was a significant success. The well was drilled six days ahead of the AFE which represented a 15% reduction in well time. In addition, at least one 12 ¼” bit was saved at a cost of +/- $60k
• For MLC-2 Oasis contracted on a straight day rate
• For future wells, BR wanted Oasis to be incentivised to improve their performance and push the technical limit, thereby further reducing costs
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The Incentive
• A bonus system introduced that was calculated as a percentage of time (cost) saved between the AFE and the technical limit.
– If the AFE was not reached no bonus was applicable
– Full bonus was achieved if the technical limit was reached or exceeded.
• Since the bonus system was linked to the technical limit, as Oasis performance improved, the more stringent their targets became.
• As the formations in MLN became better understood and targets became less onerous, the bonus system evolved to ensure that the partnership remained beneficial to both BR and Oasis.
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12 ¼” Bit Development
• Pre-drill study identified the section as a good candidate to run an experimental bit - the DP-0139
• The initial success of DP-0139 to drill the section in one run was partly due to the ability of its cutters to resist impact damage
• To build on this achievement, throughout the drilling campaign the bit design and cutting structure was modified by the BR / Oasis / Hughes team to increase the ROP without compromising durability
• The result was the Hughes Genesis bit - the HC-607
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12 ¼” Bit Development
The original experimental
Bit DP-0139 from MLC-2
Final Version: The HC-607
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Initial Results
• By November 2001, the 12 ¼” section was consistently being drilled in one run and with higher ROPs
• This performance helped place BR in the top three operators in Algeria according to an independent Rushmore benchmarking survey
Well Type TFA / Jets
Depth In Depth Out
Metres Bit Hrs Ave. ROP
MLN-8 DP 0367 7 x 11 454 2603 2149 70.5 30.4 MLSE-6 HC607 7 x 11 448 2550 2102 66.7 31.5 KMD-1 DP 0367 7 x 11 457 2571 2114 76.8 27.5
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Continuous Improvement
• In 2002 lessons from the Oasis project allowed BR to move on to a new generation of bits untested in the area and continue to improve performance
• By the end of 2002:
Well Type TFA / Jets
Depth In Depth Out
Metres Bit Hrs Ave. ROP
KMD-2 DSX113HGVW 8 x 12 428 2550 2122 49.1 43.1 MLN-11 DSX113HGVW 8 x 12 494 2632 2138 46.8 45.6
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Continuous Improvement
12-1/4" Performance
18.1
13.5
22.6
8.5
29.029.6
16.6
0
5
10
15
20
25
30
MLN-6
MLNW
-1MLC
-2MLS
E-3MLN
W-2
MLSE-4
MLW-2
MLNW
-4MLN
W-3
ZTH-1MLW
-3MLN
W-5
MLSE-5
MLS-1
MLN-7
MLN-8
MLSE-6
KMD-1MLS
E-7MLN
-9MLN
-10MLN
W-6
KMD-2MLN
-11R
OP
(m/h
r)
Bes
t Wel
l 199
9
Bes
t Wel
l 200
0
Bes
t Wel
l 200
1
Bes
t Wel
l 200
2
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3. Benchmarking
• Burlington wanted to be able to verify performance enhancement through ‘benchmarking’
• Burlington joined the Rushmore Drilling Performance Review in 1999 and the Completion Review in 2002
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Benefits of Benchmarking
Rushmore Associates provide an international forum for collatingand presenting drilling and completion performance data
Our participation:
– Establishes our competitive performance
– Provides a ‘driver’ for improvement
– Targets the big gaps and potential for improvement
– Proves and publicises achievement
– Identifies best in class and obtains indications of what best inclass companies do differently
– Validates the technical limit process
– Sets targets that are both challenging but achievable
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BR Rushmore Ranking
No. of Operators
Average m/day
Average cost/m
1999 6 3rd2000 5 1st2001 7 1st 2nd2002 6 2nd 1st2003 5 2nd 2nd
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Normalising Rushmore
• For the last two years Burlington has had the second highest average m/day, but drilled, on average, 600m shallower than the 1st placed operator
• When compared to the only well of similar depth drilled by the first placed operator in 2003, Burlington were best in class both for m/day and cost/m
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Burlington Progress M/day
0
20
40
60
80
100
120
140
160
180
200
1999 2000 2001 MLN-9(Deviated
Well)
MLN-10 MLNW-6 KMD-2 MLN-11
Metres/day
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Burlington Progress Average Cost/well
2002 data includes MLN-9 which was a deviated well, with higher associated costs.
0
1
2
3
4
5
6
7
8
9
1998 1999 2000 2001 2002
MLN-9 Effect
$mm
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‘All Inclusive’ Continuous Improvement
• As part of the continuous improvement process, well operations monitor all areas of the operation, analyse and identify areas for improvement
– Rig move times
– Hole section times
– Flat times
– Completion times
– Performance relative to technical limit
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Drilling Performance 1997 to End 2002
0
2
4
6
8
10
12
1997
MLN-3
MLNE-2
ONE-1MLN
-419
98MLS
E-1MLW
-1MLS
E-2MLN
-5MLC
-119
99MLN
-6MLN
W-1
MLC-2
MLSE-3
2000
MLNW
-2MLS
E-4MLW
-2MLN
W-4
MLNW
-3ZTH-1MLW
-3
MLN W
ater W
ell20
01MLN
W-5
MLSE-5
MLS-1
MLN-7
MLN-8
MLSE-6
KMD-1MLS
E-720
02MLN
-9MLN
-10MLN
W-6
KMD-2MLN
-11
Cos
t (U
S$m
illio
ns)
0
40
80
120
160
200
240
Day
s
Total Well Cost - Drill & Complete, Civils & Security Cost to TD, Civils & Security Time to TD
Time to Final Well Spud to TD Trend Spud to Rig Release Trend
Cost To TD, Civils & Security Trend Total Well Cost Trend