Bakken Artificial Lift & Production Congress 2013

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1 Bakken Artificial Lift & Production Congress 2013 Artificial Lift and Production Optimization Hydraulic Pumping Units Jess Babbitt, Engineering Advisor, Linn Energy

2 Hydraulic Pumping Units 2.00 Examine HPU s in Production Operations HPU s have proven to reduce downhole failures in other area s HPU s offer numerous advantages over BPU s HPU s can replace higher volume PU s for the long term HPU s offer greater operating flexibility for the long term

3 North Dakota s Production Now Exceeds Alaska Production curve for the Bakken Petroleum System (Bakken and Three Forks). Several cycles are noted on the plot: Antelope field development, Billings Nose horizontal wells, and the middle Bakken development cycle (includes Elm Coulee, Parshall, Sanish, and many other new fields). (Source: Stephen A. Sonneberg; production data from HIS) Stephen Sonnenberg, Interest, Activity Continue in the Bakken, The 2013 Playbook Bakken/Exshaw, Hart Energy, June 2013, pp 13

Bakken/Three Forks Production 1.2 m b/day Projected Bakken/Three Forks production forecast includes a selection of publically traded companies.

4 Bakken/Three Forks Production 1.2 m b/day Projected Bakken/Three Forks production forecast includes a selection of publically traded companies. (Source: North American Shale Quarterly [NASD], 1Q 2013) Maggie Salamon, Bakken: Both Sides of the Border, The 2013 Playbook Bakken/Exshaw, Hart Energy, June 2013, pp 96

Alberta Bakken Production 60 k boe/day Alberta Bakken production forecast includes a selection of publically traded companies and private companies from Hart Energy.

5 Alberta Bakken Production 60 k boe/day Alberta Bakken production forecast includes a selection of publically traded companies and private companies from Hart Energy. (Source: North American Shale Quarterly [NASD], 1Q 2013) Maggie Salamon, Bakken: Both Sides of the Border, The 2013 Playbook Bakken/Exshaw, Hart Energy, June 2013, pp 98

6 Bakken/Three Forks Cross Section Darren Barbee, The Bakken Get A Let Up, Oil and Gas Investor, Hart Energy, May 2013, pp 68

7 Typical Artificial Lift BAKKEN PLAY BPU C1280, C912 Darren Barbee, The Bakken Get A Let Up, Oil and Gas Investor, Hart Energy, May 2013, pp 69

8 RotaFlex PU s BAKKEN PLAY

9 Common Wellbore Diagram BAKKEN PLAY

10 Common Failures BAKKEN PLAY

11 Common Failures BAKKEN PLAY Lost Production Lost Production Lost Production

12 Common Failure Frequencies Potential w/o Failures Avg. Production with Failures BAKKEN PLAY Lost Production Lost Production Lost Production

High Failure Frequency 912 PU Another Operator s Perspective Operators Comments Rod pump system too large Tried reduced pump sizes Difficult to obtain correct sizing Speed x stroke

13 High Failure Frequency 912 PU Another Operator s Perspective Operators Comments Rod pump system too large Tried reduced pump sizes Difficult to obtain correct sizing Speed x stroke length changes dangerous and expensive Pulling units and crews long lead time Need a change of surface equipment to obtain slower stroke speed and stroke length over pumping is a problem

14 A Solution Hydraulic PU s vs. Conventional PU s Operator s Perspective Safety No rotating counter weights No pinch points No need for fencing around the PU Reduced rod and pump wear Easy to tag bottom Easy to change SPM Smaller foot print Reduced down hole failures Fewer workovers Adapts easily to dual casing wells

15 Operator s Perspective Hydraulic PU s vs. Conventional PU s Operator s Perspective Direct Mount Unit Requires no foundation No foundation leveling following freeze and thaw Reduced trucking costs One truck load vs. three+ Fast rig up ~3 hours Reduced Installation Costs $6K vs. ~$20K x 3days No stuffing boxes No guy wires

16 HPU Delivery vs. BPU Delivery

17 Less Rod Wear and Longer Pump Life Fewer Pulling Jobs and Less Down Time Conventional Units 912, 192 stroke, 4.5 SPM 1280, 192 stroke, 4.5 SPM Rod x Pump reversals 2.4 M times/year Hydraulic PU 300 stroke unit, 2.5SPM Rod x Pump Reversals 1.3 M million times per year 44.5% Reduction Over all benefit or reduced strokes Less rod failures reduced rod reversals Less rod wear slower travel, less friction, less stacking at the btm Lower pump intake rate may reduce sand issues Pump ware is spread out over a longer distance

18 Conventional BPU Well Performance

19 Tubing Failures and Rod Wear Near the Bottom of the Hole Add 6 10 jts. EndurAlloy tbg. (4x Harder than J 55) above SN

20 Cotton Valley Well on HPU following Minor Tubing Repair

Production by Unit Type 700 600 500 400 300

Hydraulic Unit Barrels Fluid Per Day 100 0

21 Production by Unit Type Beam Unit 1280 Beam Unit 400 Hydraulic Unit Barrels Fluid Per Day Strokes Per Minute ,960 11,520 10,080 8,640 7,200 5,760 4,320 3,600 2,520 1,800 1,080 Cycles Per Day

22 Summary HPU Alternative to conventional Possible secondary rod lift method Reduced down hole failures Easy operations Reduced cost Trucking Install Time Eliminates foundation failures

Safety, Mobility, and Power Density The Case for a 2-Rig Strategy DUG Permian-Fort Worth, TX USA Mike Dynan, VP Portfolio and Strategy April 4, 2017

Safety, Mobility, and Power Density The Case for a 2-Rig Strategy DUG Permian-Fort Worth, TX USA Mike Dynan, VP Portfolio and Strategy April 4, 2017 , Mobility, and Power Density The Case for a 2-Rig DUG Permian-Fort Worth, TX USA Mike Dynan, VP Portfolio and April 4, 2017 We all have seen the headlines The Slow Road Back: Oil & Gas Industry Outlook