AGENDA Criteria for Fluid Selection Controlling Cost Continuously Improving Performance
WELLBORE STABILITY & HOLE ENLARGEMENT DRILLING FLUIDS COMPARISON Non Aqueous Fluids (diesel, synthetic, etc.) Brine Water Fresh Water
LOST CIRCULATION Number of Techniques Creates Variability in Cost & Drilling Days Can Induce Wellbore Instability Due to Pressure Fluctuations
LOST CIRCULATION DRILLING FLUIDS COMPARISON Non Aqueous Fluids (diesel, synthetic, etc.) Brine and Fresh Water
LUBRICITY Controlling torque & drag is key to long laterals Torque & drag also affected by wellbore tortuosity and hole cleaning issues Casing run considered the best way to measure lubricity Friction between drill string, or production casing, and open hole is usually summarized as the friction factor Lubricating quality of drilling fluid described as the lubricity coefficient
DRILLING RATE DRILLING FLUIDS COMPARISON Non Aqueous (NAF) Base Fluids Brine Fluids Brine Based High Performance Drilling Fluid
CONTROLLING COST MUD LOSSES Downhole losses Mud left behind pipe after cementing Surface losses on cuttings / SCE Cost of NAF 2 to 3x s the cost of WB fluids Lost mud charges often appear after the well has reached the total depth
CONTROLLING COST LOW GRAVITY (DRILLED) SOLIDS Major Issue with NAF Historically Operator have Specified 6% by Volume or Less LGS Solutions to Controlling Low Gravity Solids in NAF Solutions for Brine Base Fluid
TOTAL COST OF DRILLING FLUIDS Fluid Products Liquid Mud Losses Fuel Charges Trucking Rentals Solids Control Equipment Environment Charges
CONTINUOUSLY IMPROVING PERFORMANCE Is the Current Drilling Fluid Meeting Expectations? Is the Drilling Fluid Really the Problem? Does the Drilling Fluid Need Improvement?
EAGLEFORD SHALE Dimmit County Well #1H OBM 8-3/4 hole @ 11,106 MD salt water influx Formation charged from field brine MW increased from 12.9 to 13.5 ppg Proposed Plan Forward Utilize Brine HP for remaining wells
EAGLEFORD SHALE Dimmit County Well #3H Surface set at 2,314 Displaced to Brine HP Drill ahead, KOP @ 6,940 MD TD hole @ 14,629 MD/7,069 TVD in 9 days
DIMMIT COUNTY 4 WELL-DAYS VS. DEPTH (SAME PAD OFFSETS) 2,000 4,000 6,000 8,000 10,000 0 2 4 6 8 10 12 14 16 18 20 22 24 Dimmit County #1- OBM Dimmit County #2- Evolution Brine- Polymer Dimmit County #3- Evolution Brine- Polymer Dimmit County #4- Evolution Brine- Polymer 12,000 14,000 16,000
DIMMIT COUNTY AVERAGE FOOTAGE PER DAY (SAME PAD OFFSETS) 94 91 102 98 0 25 50 75 100 125 Dimmit County #4-Evolution Brine-Polymer Dimmit County #2-Evolution Brine-Polymer Dimmit County #3-Evolution Brine-Polymer Dimmit County #1-OBM
DIMMIT COUNTY AVERAGE FOOTAGE PER DAY (SAME PAD OFFSETS) 753 1,022 1,219 1,066 0 200 400 600 800 1,000 1,200 1,400 Dimmit County #4-Evolution Brine-Polymer Dimmit County #2-Evolution Brine-Polymer Dimmit County #3-Evolution Brine-Polymer Dimmit County #1-OBM
BAKKEN SHALE 9-5/8 Surf. Csg @ ~2,100 MD Water 7 Int. Csg. @ ~10,250 MD OBM 6 Hole Brine HP 4 Prod. Liner Average Depth ~21,000 MD / ~11,000 TVD Average Lateral 8,000 10,000 Average Days 15-20 Longest Lateral - 14,107 MD 25,437 MD / 10,725 TVD
BAKKEN SHALE Inhibition The Salinity of Brine Prevents Hydration of Shale Improves Shale Stability Why Brine? Density Reduces the requirement of Barite, providing low solids Viscosity Reduces pressures associated with high-viscosity muds Hole cleaning due to turbulent flow ECD Management
BAKKEN PERFORMANCE 1,200' THE BRINE HP SYSTEM - BAKKEN SHALE FOOTAGE PER DAY 1,000' 871' 800' 600' 400' 626' 473' 523' 200' 0' Brine HP AVERAGE FT/DAY - TOTAL WELL OBM Offsets AVERAGE FT/DAY - PRODUCTION INTERVAL
BAKKEN PERFORMANCE 45 BRINE HP SYSTEM - BAKKEN SHALE DAYS ANALYSIS 40 35 30 25 20 15 10 5 35.1 42.6 16.5 24.5 0 Total Days on Well BRINE HP Total Production Interval Days OBM OFFSETS
WOLFCAMP B & C Drilling Fluids Considered Conventional WB HPWBM Brine Brine HP Considerations in selecting Wellbore stability Lost circulation Lubricity Drilling rate
WOLFCAMP B & C Brine HP has provided a viable alternative to NAF Recent successes in Midland, Crockett, and Reeves County Average depth, 14,000 MD/6,200 TVD 6,000 7,000 laterals 12 days, spud to TD Reduced total drilling fluid costs with equivalent, or better, drilling performance
WOLFCAMP B & C Most Recent Success in Wolfcamp B 13,500 MD 6,000 Lateral Section TD d in < 6 Days
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