AADE Mid Continent Chapter Bakken Shale Resource Play Revisited January 14, 2009 Jim Thompson
Marathon 2007 History One Year Ago Today Re-entered basin in May 2006 Hit the ground running with two conventional kelly rigs inherited with acquisition Ordered 5 New Generation Onshore Rigs Rig 1 delivered in March 2007 Rig 5 delivered in September 2007 Kept one conventional rig on payroll (released other 1/07) To date Spudded 41 wells (TD d 35) Frac d 30 wells Have run tubing in 24 Have 12 wells on rod pump 2
Marathon 2008 History Today Re-entered basin in May 2006 inheriting two conventional rigs Ordered 5 New Generation Onshore Rigs Rig 1 delivered in March 2007 & Rig 5 in September 2007 Kept one conventional rig on payroll (released other 1/07) Picked up a 7 th rig conventional in July 2008 Td d 73 wells in 2008 Frac d 65 wells in 2008 To date Drilled and TD d 108 wells Frac d 95 wells Have 40 wells on rod pump 3
2008 Areas of Activity Saskatchewan, Canada MONTANA NORTH DAKOTA Williston Ajax Hector Myrmidon Hector Area Kildeer and Dunn Center Ajax Area Manning Myrmidon Area - FBIR Dickinson 4
Bakken Well Construction No Changes in 2008 MOC Drilling Program: Set 16 Conductor at +/- 90 Drill 13-1/2 hole to +/- 2100 Set 9-5/8 Surface Casing +/- 90 16 Conductor Drill 8-3/4 Intermediate Hole w/obm, PDC bits, motors +/- 2100 OBM 9-5/8 Surface Vertical to +/-10,200 KOP Drill curve w/12-13 deg./100 BR Land curve in MB interval at +/- 11,000 ( 87-90 deg.) Set 7 production casing KOP +/- 10200 12-13 deg./100 Build Displace OBM w/ brine mud Drill +/- 9000 of 6 lateral to +/- 20,000 TMD Employ vibration technology when req d (16,000 +) +/- 11000 7 Production Brine based mud 9000 6 Hole 5
6 Drilling Technologies Use Where Appropriate Directional Drilling (ROP & Stay in Zone) Rotary Steerables Vibration vs Oscillation Adjustable gauge stabilizers Turbines (ROP) OBM in lateral High Pressure rotating heads for UBD PDC Bit / Motor Assemblies (ROP) Top Drive Casing Running Tool Even Wall / Hardened Rubber Motors Resistivity Steering RFID Circ Sub
Increasing Bakken Drilling Efficiency M e a s u r e d D e p t h, F t. 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 7 Bakken Drilling Trends - 2006 to Present 17000 18000 19000 20000 21000 0 10 20 30 40 50 60 Days 2006 Days vs. Depth 2006 Days vs. Depth 2007 Days vs. Depth 2006 Days vs. Depth 2008 Days vs. Depth 2007 Days vs. Depth 2008 Bench Metric Avg. Drlg. $MM Avg. Ft/Day 2006 5.93 376 2007 4.22 525 *Hector/Ajax/Mymidon Areas based upon wells TD d Reducing well cost, cycle times while providing superior safety culture / environment >40% cost reduction 2008 3.46 811 >50% drilling time reduction
MOC Performance Comparison 17500 2008 Bakken - Hector/Ajax Drilling Benchmark Performance 82% of MOC Operated Wells in Top Quartile MOC Operated OBO OBO Top Quartile Line 18500 Total Measured Depth, Ft. 19500 20500 8 21500 15 20 25 30 35 40 45 Days Source: WI OBO wells and bit records
MOC Performance Comparison 19500 2008 Bakken - Myrmidon Drilling Benchmark Performance MOC Operated OBO OBO Top Quartile Line 20000 Total Measured Depth, Ft. 20500 100% of MOC Operated Wells in Top Quartile 21000 21500 20 25 30 35 40 45 50 9 Days Source: WI OBO wells and bit records
Marathon Bakken Drilling Milestones Vertical hole section footage in any 24 hour drilling report time period 4500 + Lateral hole section footage in any 24 hour drilling report time period 3000 + Numerous single BHA lateral runs Drilling Benchmark of 19824 in 17.3 days for 1145 ft/day all in avg. ROP Drilling benchmark Spud to KOP at 10182 in less than 7 days Numerous wells drilled for under $3MM Rig Move Benchmark Rig Release to Spud of 2.3 days Technical Limit Curve of 14 days to 20,000 Improved Drilling Processes 7 casing procedure proving very successful Rigsite Teams in place with outstanding Teamwork Solid/Sound Engineering 10
Bakken Challenges Continuous Improvement Top tier HES performance Drilling Execution + step changes ROP and flat time Directional Tool reliability Stay in zone smoothly and while rotating 11
North Dakota Middle Bakken Stratigraphy Not Always the Same Bakken Interval Type Log GR Res Bakken Upper Shale 50 to 90 in North Dakota Middle Member 30 to 70 Drilling Target FG to MG SS Dolo or LS Very FG SS, slt. st. heavily burrowed Siltstone, calcite cement Brachiopods, crinoids Middle Member Consider the complete Bakken interval a hydrocarbon system (reservoir and source) Mixed lithology Oil saturated but very tight Drilling target ~14 Lower Shale 12
Initial Bakken Completions Evaluation B Cas Press (psi) 6000 B Rate (bpm) C BH Prop (lb/gal) D C D Technology/Tools for Uncemented Liner Completion Evaluation 150 50 Pressure Transient Analysis Richland 125 Effective RA Tracers/Logs County, MT 40 Fracture Growth Volume Distribution 5000 4000 Heel 10% Middle 40% K002D diversion Tiltmeter FracK004D Mapping Some early 50% Toe diversion 16 K001D 100 K005D K076D Frac Pump Curve Analysis 30 K006D K077D K080D Evaluation Results K078D 45% Longitudinal 35% Horizontal 20% K008D K015D K009D 75 K012D K016D K019D K007D K075D Transverse PTA less than desired effective wellbore length 20 K079D indicated Klatt 31-14 K018D K003D 3000 9-5/8 K020D 50 K074D Wells treated uniformly unlike Richland County, Montana K021D K073D K014D K029D Toe to 10 Heel Mapping indicated K022D self diverting treatment K011D K072D 2000 K068D K069D 25 K028D K010D K023D K025S LittleK070D to nok067d NetK030D Pressure Build K027D during Frac Jobs 1000 10:00 5/19/2004 K031D K017D K032D 0fluids K026D Liner w/higher cost Frac not required for diversion? Try open K013D K035D K066D 12:00 13:00 14:00 K065D K033D K034D hole linerless water fracs. TimeK063D K064D K024D 11:00 0 5/19/2004 K038D K058D UBS 7 K045D K060D K041D K040D K042D K057D K046D MBS K047D K055D K036D K039D K059D K071D K062D K061D K037D K056D K044D 9000 K043D 6 Hole K053D K048D LBS K054D K052D K049D K050D 13 Typical MOC Frac job
Bakken Completions Current Methodology Open Hole Linerless Water Frac Completions 16 9-5/8 9000 Single Lateral Well Construction Cost savings of +/- $600M Slick Water Frac Fluid at proppant conc. of.4-.8 ppg Complex Frac Geometry along wellbore (Longitudinal and Transverse) Completed 79 wells with this Methodology UBS 7 MBS 9000 6 Hole LBS 14
Bakken Completions UBS MBS Volume Distribution Heel Middle Toe 45% 30% 25% 9-5/8 7 16 Fracture Growth Technology/Tools for Open Hole Completion Evaluation Tiltmeter Frac Mapping K005D K001D Micro K076D Seismic Frac Mapping K077D K080D Evaluation K078D Results K071D K062D K061D K072D K063D K075D K079D Tiltmeter K003Dmapping Klatt 31-14 indicated K018D Toe to Heel self diverting K020D K074D treatment K073D with different orientation K011D K068D Micro Seismic K029D mapping K022Dresults being finalized. Shows K069D K028D K023D K010D micro seismic events along K025S entire wellbore (more heel K067D K027D K070D K030D to toe) K017D K031D K013D K066D K065D K033D Open K064D Hole completions w/lower K034D cost Frac fluids K038D comparable to Liner K037D w/crosslinked K036D frac Fluid K058D K059D K039D Methodology. K060D K055D K002D K024D K057D K056D K004D K045D K046D K006D K007D K053D K047D K008D K009D K014D K040D K048D K015D K019D K021D K044D K043D K032D K012D K016D K026D K041D K042D K035D Transverse Longitudinal Oblique Horizontal 45% 30% 15% 10% 9000 6 Hole LBS K054D K052D K050D K049D 15
Completions Challenges Completions Effective wellbore length (optimized stimulation) Refracs? Technology application to evaluate current methodology Change if appropriate Cycle time 16
17 QUESTIONS?