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  • 7th Annual Sucker Rod Pumping Workshop

    Renaissance Hotel Oklahoma City, Oklahoma September 27 - 30, 2011

    Experience Rod Pumping Deviated CBM Wells Tom Cochrane, Evan Lamoreux, Leanna Marquez, Dave Allison ConocoPhillips, San Juan Business Unit

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 2

    Deviated Well Rod Pumping

    Content S Wells Horizontal Wells Friction Reduction Failure Trend

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 3

    Deviated Well Rod Pumping

    Failure Root Cause & Repair Cost

    All Rod Pump Downhole Repairs.

    Vertical and deviated wells. Coal fines plug pumps and

    cover up intakes. Wear driven by pump

    tagging due to fines in pump valves.

    2010 Rod Pump Repair Costs

    $0

    $500,000

    $1,000,000

    $1,500,000

    $2,000,000

    $2,500,000

    Coal Wear Scale Corrosion Sand Other

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 4

    S Shaped Wells

    Vertical from surface

    Upper curve

    Slant Section

    Lower Curve

    Vertical through completion

    Allow us to drill infills from existing locations, and avoid surface features that are not drilling-friendly (rivers, inaccessible mesas, population).

    Fruitland Coal

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 5

    S Shaped Wells

    Many S wells have long run times despite significant side loads and doglegs.

    Historical failures attributed to wear were probably accelerated by corrosion, pre-repair tubing wear, and wellbore conditions.

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 6

    S Shaped Wells

    48 S and 3 horizontal wells on rod pump.

    Four S wells were pulled due to high gas rate, repeated coal fines failures, or recompletions.

    Most are Fruitland Coal CBM wells in northwest NM.

    S wells pumping now, have been running an average of 3 years.

    2010 failure rate for S wells was 0.13 failures per well per year.

    Deviated wells subject to same failure modes as vertical wells.

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 7

    S Shaped Wells

    Run and running times for different failure causes

    Running wells are systems still running in the field; running time is pessimistic to run time. Running time would equal run time if they all failed today.

    We have acceptable running times for most of our deviated wells.

    Many failures due to typical San Juan Basin CBM rod pumping issues.

    Wear is apparently the issue that creates the shortest run times.

    Years

    0.0

    0.5

    1.0

    1.5

    2.0

    2.5

    3.0

    3.5

    Running

    Scale

    Corrosion

    Coal

    Pump

    Wear

    Unknow

    n

    Failure Cause

    Ave

    rage

    Yea

    rs to

    Fai

    lure

    Running Times for Active Wells, Run Times for Failures, vs. Failure Cause

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 8

    S Shaped Wells

    S curves are measured by dogleg, and with the rod load, determine sideload.

    For an S well, the shallow curve is usually more important to the side load calculation because more of the rod string weight is dragged across the upper curve, than the lower curve.

    Lower curve dogleg has less side load, for similar dogleg.

    We expect wear to be a close function of side load.

  • "S" Well Wear Failures and Active Wells

    0

    2

    4

    6

    8

    10

    12

    14

    0 100 200 300 400 500

    Side Load, Pounds

    Run

    Tim

    e, R

    unni

    ng T

    ime,

    Yea

    rs

    Wear Fails, Side Load at Failure Running, Max. Side Load in Well

    Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 9

    S Shaped Wells

    Running and Run Times Green boxes are for our

    12 top running time S wells. Running times for

    systems/wells still operating in the field are on the left axis.

    These are plotted against the maximum sideload in the well.

    Red circle data are S well failures attributed to wear. Run times from repair

    to failure on the left axis

    These are plotted against the sideload at the failure depth.

    Active wells still running

    Wear failures

  • "S" Well Wear Failures and Active Wells

    0

    2

    4

    6

    8

    10

    12

    14

    0 100 200 300 400 500

    Side Load, Pounds

    Run

    Tim

    e, R

    unni

    ng T

    ime,

    Yea

    rs

    Wear Fails, Side Load at Failure Running, Max. Side Load in Well

    Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 10

    S Shaped Wells Running and Run Times We expect side load to

    have a direct effect on wear, runtime and failures.

    Wear failures surprisingly have a lower range of side load than the longer running wells.

    This suggests the failures are not completely wear-related.

    Wear failures

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 11

    S Shaped Wells

    Well paths of past failures attributed to wear.

    Only three of ten wear wells have horizontal travel > 1,500.

    Many have fairly limited deviations, that should not enhance wear of rods on tubing.

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 12

    S Shaped Wells

    Well Geometry Factors

    Long Run Wells vs. Wear Failures

    Slightly higher side loads in wear failure wells.

    Longer curve lengths in long running time wells.

    Average Wear Fails Running Time, years 0.7 6.5 Maximum Upper Lateral Dogleg, 5.1 6.0 degrees/100 Side Load, lbf 240 216 Upper Curve Length, feet 634 782 Lower Curve Length, feet 591 813

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 13

    Tubing Leaks attributed to wear, depths

    Many of these tubing leaks dont occur at points wed expect wear to occur;

    In curves, due to side load wear.

    Near seating (F) nipple due to tagging.

    S Shaped Wells

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 14

    Wear failure well. Two wear failures

    in same well. Left charts are

    tubing wall loss vs. depth from wellhead tubing inspection.

    This well has two recent failures in 200# side load section.

    First failure after 2 years, second after 7 months.

    Wear holes at upper curve probably accelerated by corrosion seen on left side of chart.

    Tubing Joint Wall Loss vs. Depth

    Corrosion

    Wear

  • "S" Well Wear Failures and Active Wells

    0

    2

    4

    6

    8

    10

    12

    14

    0 100 200 300 400 500

    Side Load, Pounds

    Run

    Tim

    e, R

    unni

    ng T

    ime,

    Yea

    rs

    Wear Fails, Side Load at Failure Running, Max. Side Load in Well

    Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 15

    S Shaped Wells

    Running and Run Times Two wells occur twice

    on the chart. Early, quick failure not

    at max side load depth, followed by 5.5 year run so far.

    Something besides wear on new tubing created the earlier failure; a wellbore condition, completion debris, or previously worn or corroded tubing.

    Same Well

    Same Well

  • "S" Well Wear Failures and Active Wells

    0

    2

    4

    6

    8

    10

    12

    14

    0 100 200 300 400 500

    Side Load, Pounds

    Run

    Tim

    e, R

    unni

    ng T

    ime,

    Yea

    rs

    Wear Fails, Side Load at Failure Running, Max. Side Load in Well

    Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 16

    S Shaped Wells

    Running and Run Times With no mitigating factors

    like corrosion, coal, etc. Side load < 150 lbs we

    can run up to 12 years. 150# < Side load < 415#,

    run times > 4.6 years. Artificial Lift Group

    started in 4/2009 brings increased emphasis to failure root cause analysis.

    Wells still running, run time increasing

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 17

    Horizontal Wells

    We are rod pumping 3 horizontal wells Less complicated than S wells. Horizontal wells have one curve, lower in the

    well, so side loads are typically lower. No wear failures to date.

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop

    Horizontal Wells

    We are pumping three horizontal wells from in the curve;

    Well 1 Toe up, pumping from 86 degrees in curve, corod. Installed rod pump 9/2008. Corrosion repair 12/2009.

    Well 2 Toe up, pumping from the heel at 88 degrees. Ran 10/2010.

    Well 3 Toe down, pumping from 88 degrees in curve. well now flows so much we dont have to run the pump. Ran 11/2010.

    Because doglegs are deeper in well, less side load issues than S wells.

    S well

    Horizontal Heel Toe-Up

  • Sept. 27 - 30, 2011 2011 Sucker Rod Pumping Workshop 19

    Friction and Wear Reduction High Density Polyethylene-Lined Tubing Significantly reduces internal corrosion Significant reduction in friction and wear 12 Current Installs - (No Wear Failures) S wells

    Average Max DLS - 7.3 Deg Max DLS - 8.8 Deg

    Rodstar Calculated Side Load Reduction Average Side Load Reduction-

    22.17% Maximum Side Load Reduction-

    25.41% Miniumum Side Load Reduction- 16.79%

    One recent repair incorporated continuous/

    coiled sucker rod in con

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