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Reducing Well Costs MLN Field, Algeria

Neal Whatson

Burlington Resources Algeria LLC

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.

3

Algeria - Block 405a

Block 405

Hassi Messaoud

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

5

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

6

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

7

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

8

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

9

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)

10

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)

?

11

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

12

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

13

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

14

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

15

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

16

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

17

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

18

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

19

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

20

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.

21

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

22

12 ¼” Bit Development

The original experimental

Bit DP-0139 from MLC-2

Final Version: The HC-607

23

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

24

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

25

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

26

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

27

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

28

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

29

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

30

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

31

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

32

‘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

33

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