Experience Rod Pumping Deviated CBM Wells

Transcription

1 7 th 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

2 Deviated Well Rod Pumping Content S Wells Horizontal Wells Friction Reduction Failure Trend 2011 Sucker Rod Pumping Workshop 2

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. $2,500,000 $2,000,000 $1,500,000 $1,000,000 $500,000 $ Rod Pump Repair Costs Coal Wear Scale Corrosion Sand Other 2011 Sucker Rod Pumping Workshop 3

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 2011 Sucker Rod Pumping Workshop 4

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 Sucker Rod Pumping Workshop 5

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 failure rate for S wells was 0.13 failures per well per year. Deviated wells subject to same failure modes as vertical wells Sucker Rod Pumping Workshop 6

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. Average Years to Failure Running Times for Active Years Wells, Run Times for Failures, vs. Failure Cause Unknown Wear Pump Coal Corrosion Scale Running Failure Cause 2011 Sucker Rod Pumping Workshop 7

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 Sucker Rod Pumping Workshop 8

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. Run Time, Running Time, Years "S" Well Wear Failures and Active Wells Active wells still running Wear failures Side Load, Pounds Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 9

10 S Shaped Wells Running and Run Times "S" Well Wear Failures and Active Wells 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 wearrelated. Run Time, Running Time, Years Wear failures Side Load, Pounds Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 10

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 Sucker Rod Pumping Workshop 11

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 Maximum Upper Lateral Dogleg, degrees/100 Side Load, lbf Upper Curve Length, feet Lower Curve Length, feet Sucker Rod Pumping Workshop 12

13 S Shaped Wells Tubing Leaks attributed to wear, depths Many of these tubing leaks don t occur at points we d expect wear to occur; In curves, due to side load wear. Near seating (F) nipple due to tagging Sucker Rod Pumping Workshop 13

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. C o r r o s i o n W e a r Tubing Joint Wall Loss vs. Depth 2011 Sucker Rod Pumping Workshop 14

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. Run Time, Running Time, Years "S" Well Wear Failures and Active Wells Same Well Same Well Side Load, Pounds Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 15

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. Run Time, Running Time, Years "S" Well Wear Failures and Active Wells Side Load, Pounds Wells still running, run time increasing Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 16

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 Sucker Rod Pumping Workshop 17

18 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 don t 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 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 Deg Max DLS Deg Rodstar Calculated Side Load Reduction Average Side Load Reduction % Maximum Side Load Reduction % Miniumum Side Load Reduction % One recent repair incorporated continuous/ coiled sucker rod in conjunction with polytubing Sucker Rod Pumping Workshop 19

20 Friction and Wear Reduction Runtime Improvement Poly Lined Tubing Repeat Failure Wells Well A Well B S Well Previous Average Runtime Days (13 Failures- 9 Wear) Average Poly Runtime Days (1 Failure- Not Wear) Current Poly Running Time Days Previous Average Runtime Days (3 Failures- 1 Wear) Current Poly Running Time 1,212 Days Well C (Sidetrack) Well D Previous Average Runtime Days (10 Failures- 5 Wear) Poly Running Time Days Previous Average Runtime - 84 Days (2 Failures- 1 Wear) Current Poly Running Time 1,079 Days Sidetrack 2011 Sucker Rod Pumping Workshop 20

21 Dynamom eter Card Date Months run before Dynamome ter S Well with Rod Guides Installation Date RODSTAR Coefficient Well 1 9/10/ /14/ Well 2 9/25/2007 5/12/ Well 3 4/4/ /14/ Well 4 2/17/2009 4/28/ Well 5 10/9/2007 2/23/ Well 6 8/9/2006 2/19/ Well 7 7/28/2008 9/8/ Well 8 11/21/2005 8/10/ Well 9 8/19/ /17/ Well 10 5/13/2004 3/26/ Well 11 7/14/2006 6/25/ Average Rod Guided Wells Empirical Friction Factors Matched Peak Polish Rod Load PPRL so predictions of unit loads would be close. More friction than bare tubing (0.26 vs. 0.20). SROD Coefficient 2011 Sucker Rod Pumping Workshop 21

22 Friction and Wear Reduction Poly-lined Tubing "S" Wells Months run before Dynamome ter Installation Date Card Date RODSTAR Coefficient Well 12 1/19/2009 9/28/ Well 13 8/25/ /14/ Well 14 3/1/2008 9/28/ Well 15 6/4/2008 9/17/ Average Poly-Lined Tubing Wells Empirical Friction Factors Matched Peak Polish Rod Load PPRL so predictions of unit loads would be close. Significant reduction in rod/tubing friction vs. rod guides or bare tubing (0.09 vs or 0.20). Less friction should result in less wear. SROD Coefficient 2011 Sucker Rod Pumping Workshop 22

23 S Well Failure Trend Failure rates steady since program started, with 2010 a very good year Sucker Rod Pumping Workshop 23

24 Failure Trend S Well Failure Rate "S" Well Failure Trend 0.60 Better tubing replacement procedures. Poly-lined tubing. Four problem wells taken off rod pump. Less fluid energy and pressure to move coal fines. Downhole pump & bottom-hole assembly standards. Failures per Well per Year Sucker Rod Pumping Workshop 24

25 Deviated Well Rod Pumping - Summary S Wells Wear not a significant factor in runtimes. Use of poly tubing should further improve runtimes. Horizontal Wells 3 wells producing. Leveraging S well learnings. Friction Reduction Poly-lined tubing reduces friction vs. bare tubing, and should reduce wear. Already seeing increased run times, especially in repeat failure wells. Failure Trend Historically around 0.3 failures per well per year failures per well per year in Sucker Rod Pumping Workshop 25

26 Deviated Well Rod Pumping Questions? 2011 Sucker Rod Pumping Workshop 26

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