Bakken Artificial Lift

© 2007 Weatherford. All rights reserved.

Bakken Artificial Lift

Don ConnallyDate: May 2, 2010


Defining Production Optimization

• Increase production

– Lower mean failure rate

– Increase flow rate

– Maximize reservoir production

• Lower costs

– Reduce down times

– Improve system efficiency

– Maximize human resource potential

– Doing more with less

op· ti· mi· za· tion (Ŏp΄tə-mĭ-zā′shən)

n. The procedure or procedures used to make a system or design as effective or functional as possible


Optimum Rod Lift System

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Rotaflex Long Stroke Pumping Unit

• First successful long stroke pumping unit with over 20 years of manufacturing and 7000 units installed worldwide

• 100% mechanical design -uncomplicated with low maintenance

• Longer stroke lengths (Up to 366 inches or 9.3 Meters) provide higher pump compression ratios to help prevent gas lock problems

• High Production Rates up to 10,000 BPD

• Alternative to:– Electric submersible pumps– Hydraulic jet pumps– Large conventional units

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Rotaflex Long Stroke Pumping Unit

• Fewer cycles and reversals on pumps and rods leads to lower failure rates

• 40 to 60% reduction in rod reversals = Improved subsurface equipment life

• High system efficiency and cost effectiveness for deep, troublesome, and high-volume wells

• 20 to 50% reduction in electrical costs & Horsepower required

• Lower peak power demand4

© 2007 Weatherford. All rights reserved. 5

System Efficiency Comparison

• Highly efficient pumping system

0%

10%

20%

30%

40%

50%

60%

70%

ESP Conv PC RF


Rotaflex Long Stroke Production Capabilities

0

2000

4000

6000

8000

10000

1200020

0025

0030

0035

0040

0045

0050

0055

0060

0065

0070

0075

0080

0085

0090

0095

0010

000

1050

011

000

1150

012

000

RF 800DXRP 900RF 1100RF 1150RF 1151

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Cycles Comparison

• 8 spm

• 4,204,800 strokes per year

• 2.37 years to acquire 10 million cycles on rods

• 4 spm

• 2,102,400 strokes per year

• 4.75 years to acquire 10 million cycles on rods

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Rotaflex vs. Conventional Pumping Units

• Well Parameters

– Pump Depth: 9800 ft (2987 meters)

– Fluid Level: 9600 ft (2926 meters)

– Production Required: 500 BPD (79.5 m3)

– Tubing: 2-7/8” (70.025 mm)

– Pump: 2.25” (57.15 mm) Tubing Pump

– Rod String: High strength 86 Taper

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Rod Star Results

Conv.1280-427-192

Mark II 1824-427-216

Rotaflex 1100 320-500-306

Production 496 494 505

Strokes Per Minute 7.64 7.08 4.38

Gear Reducer Torque 1,447,000 2,006,000 262,000

PPRL/MPRL 44,540/12,630 44,704/12,300 42,443/14,537

Rod Stress 102% 103% 92%

Electric Motor 125 HP 150 HP 100 HP

Electrical Usage $ / BBP/Month $0.183/$2776 $0.189/$2845 $0.132/$2030

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Rotaflex vs. ESP Operating Costs

Long Stroke ESP

Installation $250,000 $250,000

Servicing $45,000 $100,000

Power Costs/Month $1,300 $1,900

Run Life (Days) 730 730

$/BOE $3.32 $6.34

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Based on SPE paper, SPE 68791

600 barrels/day fluid--326 bpd of oil


• Alternative to conventional sucker rods

– Only two connections at the top and bottom of the rod string

• Over 44 years of manufacturing, applications and service history

• Installed in 16,500+ wells worldwide

Reel of Continuous Rod

COROD Continuous Sucker Rod


Why use COROD Continuous Rod?

• Most common sucker rod failures are pin failures due to improper joint make-up. Less connections = less failures.

– Number of connections in a 3,000m / 9,900 ft well:

• Continuous rod: 2

• Conventional rod: 327

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BOX & PIN 65%

TBG LEAKS10%

BODY BREAKS 25%

BOX & PINTBG LEAKSBODY BREAKS

BOX & PIN 65%

TBG LEAKS10%

BODY BREAKS 25%

BOX & PINTBG LEAKSBODY BREAKS


Sucker Rod


1. Fewer threaded connections

2. Reduced rod-tubing wear due to uniform load distribution.

– 150 times lower for RRP

– 50 to 75 times lower for PCP

– Most pronounced in deviated wells.

Sucker Rodw/ Guides

COROD

Severe Wear AreasUniform Load Distribution

Tubing

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2. Reduced rod-tubing wear

3. Larger annular space

– Minimizes flowing pressure losses associated with rod guides, couplings, centralizers

– No coupling piston effect

– Effective in deep holes with small tubing. All COROD®

sizes fit in 2-3/8” tubing.

– Increased flexibility of rod string design and capacity due to elimination of couplings

1'’ Slim Hole Coupling

1'’ CORODVS.

2 7/8” Tubing(Cross-sectional view)

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2. Reduced rod-tubing wear

3. Larger annular space

4. Lighter in weight

– Continuous rod strings are lighter than conventional sucker rod strings of the same length, reducing the weight on the pumping unit.

Length of Rod String m (ft)

Type of Rod String

Difference (%)1” Conv. Sucker Rod w/ couplings (lb)

COROD® (lb)

1,000 (3,280) 9,508 8,754 8

1,500 (4,921) 14,262 13,131 8

2,000 (6,561) 19,016 17,508 8

Conventional sucker rods = 8% heavier than continuous rod


COROD versus Jointed Sucker Rod

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Reduced Maintenance& Operational Costs+Reduced Capital

Costs per Well

• Longer tubing life

• Longer rod system life

• Increased pump life

• Smaller surface equipment• Smaller rod pump• Lower power consumption• Works in smaller tubing

Reduced Costs &Improved Efficiency

• Lower rod-tubing contact stresses

• Only 2 connections• Eliminates coupling piston effects

• Larger annular space between rod and tubing

• Reduced flow resistance

• Lighter weight

CAPEX OPEX


Round Rod• Rotary rod (PCP)

• Reciprocating rod (RRP)

• Reduced contact load (50 - 75x)

• Maximum working torque = 2,000 lb-ft (2,712 nM)

Semi-elliptical• Reciprocating rod (RRP)

• Reduced contact load (150x)

• Reduced spooling diameter

• Equivalent to round sizes from 3/4” to 1-1/8” (19 mm - 28.6 mm)

COROD Continuous Rod Options

22 33 44 55

66 77 88

3 4 6 8.5

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© 2007 Weatherford. All rights reserved. Weatherford Confidential Slide 18

Automation Value Proposition – Direct Benefits

• Manage decline curve –max production / min barrel cost

• Extend the life of field decline & increase total recovery

• Reduce failures and operating expense

• Optimize manpower utilization

• Indirect benefits – failure detection/prevention


Why Use a Rod Pump Optimization Controller?

• The basic benefits obtained from a rod pump controller are:

– Detection and control of pump off (fluid pound)

– Maximize well production

– Minimum power usage

– Protection of pumping system components

• Other benefits of an RPC include guarding against or detection of:

– Worn pumps plugged pump intakes

– Leaking standing or traveling valves

– Tubing leaks

– Rod parts / stuck or tight pumps

– Gas lock situations

– Rod overload / underload

– Automatic restart after power failure


WellPilot Rod Pump Controllers

• Important features

– Ease of use

– Control from down-hole pump fillage

– Dynamometer card accuracy

– Auto-determine down-hole friction

– Calculation in controller and host

– Rod Stress calculation on each taper

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WellPilot Rod Pump Optimization Controllers

• Pump fillage percent control verses surface and downhole card control

• Everitt-Jennings verses Gibbs calculations

• Built in real-time production well testing

• Open design to accommodate future applications

• Fixed-speed control

• Variable-speed control

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WellPilot Variable Speed Drive Option

• Adjustable manual SPM settings at constant speed

• Increase maximum average SPM 15 - 20% withthree speed operation

• Separate adjustments for upstroke and downstroke SPM settings

• Integrated Rod pump Controller

• Optimization Mode based on Pump Fillage allowing continuous operation of the system

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© 2007 Weatherford. All rights reserved. Weatherford Confidential Slide 23

Host Software Business Case

Increase Production• Reduce Well Downtime

– Directly reduce Intervention and failure rate– Identification of Workover Opportunities– Prioritize Opportunities for Best Results

• Optimize Well Production Using Automation– Tune Wells for Optimum Performance– Properly Size Equipment to Deliverability

• Standardized Well Accounting – Production Allocation

Reduce Expenses

• Flexibility to Select Controllers and RTU Devices

• Simplified Field Telecommunications / Platform

• Workover Rig Backlog Management

• Implement Best Practices

– Root Cause Failure Identification

– Change Processes / Procedures

Rev

enue

Expenses


LOWIS Host Software

• Life of the well software

– Early detection of downtime

– Quickly identify, prioritize, plan and service poor performing wells

• Asset scheduling software

– Efficient rig scheduling

• Well service management

– Workover planning and forecasting

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LOWIS Host Software

• Life of the well information system

– Management by exception helps quickly identify resource-draining wells

– Efficient use of human resources

• Analysis Workbench

– Analyze artificial lifted wells in real time

• Well Services Management

– Proactive management of well maintenance

– Efficient use of assets

– Identify best practices

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Software Needs

• Applications for subsurface to surface modeling, analysis, design, and optimization

– All forms of artificial lift

– Well design

– Reservoir monitoring

– Well testing

– Workflow management

– Knowledge management.

© 2007 Weatherford. All rights reserved. Slide 27

• $6 million per year annual savings – Real Dollar Benefit

• Technology: Controllers / Software• Process: Process standards• People: Teamwork

Customer Value: San Juaquin Valley


Conclusions: What are the benefits?

• Long Stroke Pumping Unit + Continuous Sucker Rod + VFD & Rod Pump Optimization Controller + Host Software = Higher production rates, Reduced Maintenance and Operational Costs

– Reducing the stroke cycles by 35% - 50% and severity of mechanical wear between tubing and rods should increase the life of the tubing, sucker rods and downhole pump.

– Lowers peak rod stress and increases range of load on rods for improved rod life

– 20-50% Reduction in electrical costs and horsepower

– Longer stroke provide higher pump compression ratios to help prevent gas lock problems

– Minimizes deferred production and downtime due to failures.

– Minimizing fluid and gas pound reduces mechanical failures to the tubing, rod, pump and pumping unit.

– Unique hardware design characteristics allow for higher lift system capacities and increased production capability.


QUESTIONS?

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Bakken Artificial Lift