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
Deviated Well Rod Pumping Content S Wells Horizontal Wells Friction Reduction Failure Trend 2011 Sucker Rod Pumping Workshop 2
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 $0 2010 Rod Pump Repair Costs Coal Wear Scale Corrosion Sand Other 2011 Sucker Rod Pumping Workshop 3
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
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. 2011 Sucker Rod Pumping Workshop 5
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. 2011 Sucker Rod Pumping Workshop 6
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 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 Unknown Wear Pump Coal Corrosion Scale Running Failure Cause 2011 Sucker Rod Pumping Workshop 7
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. 2011 Sucker Rod Pumping Workshop 8
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 14 12 10 8 6 4 2 0 Active wells still running Wear failures 0 100 200 300 400 500 Side Load, Pounds Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 9
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 14 12 10 8 6 4 2 Wear failures 0 0 100 200 300 400 500 Side Load, Pounds Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 10
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. 2011 Sucker Rod Pumping Workshop 11
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 2011 Sucker Rod Pumping Workshop 12
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. 2011 Sucker Rod Pumping Workshop 13
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
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 14 12 10 8 6 4 2 0 "S" Well Wear Failures and Active Wells Same Well Same Well 0 100 200 300 400 500 Side Load, Pounds Wear Fails, Side Load at Failure Running, Max. Side Load in Well 2011 Sucker Rod Pumping Workshop 15
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 14 12 10 8 6 4 2 0 "S" Well Wear Failures and Active Wells 0 100 200 300 400 500 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
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. 2011 Sucker Rod Pumping Workshop 17
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
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 conjunction with polytubing. 2011 Sucker Rod Pumping Workshop 19
Friction and Wear Reduction Runtime Improvement Poly Lined Tubing Repeat Failure Wells Well A Well B S Well Previous Average Runtime - 273 Days (13 Failures- 9 Wear) Average Poly Runtime - 650 Days (1 Failure- Not Wear) Current Poly Running Time - 167 Days Previous Average Runtime - 679 Days (3 Failures- 1 Wear) Current Poly Running Time 1,212 Days Well C (Sidetrack) Well D Previous Average Runtime - 313 Days (10 Failures- 5 Wear) Poly Running Time - 427 Days Previous Average Runtime - 84 Days (2 Failures- 1 Wear) Current Poly Running Time 1,079 Days Sidetrack 2011 Sucker Rod Pumping Workshop 20
Dynamom eter Card Date Months run before Dynamome ter S Well with Rod Guides Installation Date RODSTAR Coefficient Well 1 9/10/2007 11/14/2007 2 0.40 0.40 Well 2 9/25/2007 5/12/2008 8 0.25 0.25 Well 3 4/4/2008 11/14/2008 7 0.20 0.18 Well 4 2/17/2009 4/28/2009 2 0.34 0.38 Well 5 10/9/2007 2/23/2010 29 0.31 0.29 Well 6 8/9/2006 2/19/2010 43 0.29 0.34 Well 7 7/28/2008 9/8/2009 14 0.20 0.21 Well 8 11/21/2005 8/10/2009 45 0.25 0.27 Well 9 8/19/2005 12/17/2009 53 0.31 0.32 Well 10 5/13/2004 3/26/2009 59 0.20 0.20 Well 11 7/14/2006 6/25/2009 36 0.16 0.19 Average 0.26 0.28 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
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 9/28/2009 8 0.15 0.16 Well 13 8/25/2008 10/14/2009 14 0.02 0.04 Well 14 3/1/2008 9/28/2009 19 0.10 0.07 Well 15 6/4/2008 9/17/2009 16 0.07 0.10 Average 0.09 0.09 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. 0.26 or 0.20). Less friction should result in less wear. SROD Coefficient 2011 Sucker Rod Pumping Workshop 22
S Well Failure Trend Failure rates steady since program started, with 2010 a very good year. 2011 Sucker Rod Pumping Workshop 23
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 0.50 0.40 0.30 0.20 0.10 0.00 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Sucker Rod Pumping Workshop 24
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. 0.13 failures per well per year in 2010. 2011 Sucker Rod Pumping Workshop 25
Deviated Well Rod Pumping Questions? 2011 Sucker Rod Pumping Workshop 26
Copyright Rights to this presentation are owned by the company(ies) and/or author(s) listed on the title page. By submitting this presentation to the Sucker Rod Pumping Workshop, they grant to the Workshop, the Artificial Lift Research and Development Council (ALRDC), and the Southwestern Petroleum Short Course (SWPSC), rights to: Display the presentation at the Workshop. Place it on the www.alrdc.com web site, with access to the site to be as directed by the Workshop Steering Committee. Place it on a CD for distribution and/or sale as directed by the Workshop Steering Committee. Other use of this presentation is prohibited without the expressed written permission of the author(s). The owner company(ies) and/or author(s) may publish this material in other journals or magazines if they refer to the Sucker Rod Pumping Workshop where it was first presented. 2011 Sucker Rod Pumping Workshop 27
Disclaimer The following disclaimer shall be included as the last page of a Technical Presentation or Continuing Education Course. A similar disclaimer is included on the front page of the Sucker Rod Pumping Web Site. The Artificial Lift Research and Development Council and its officers and trustees, and the Sucker Rod Pumping Workshop Steering Committee members, and their supporting organizations and companies (here-in-after referred to as the Sponsoring Organizations), and the author(s) of this Technical Presentation or Continuing Education Training Course and their company(ies), provide this presentation and/or training material at the Sucker Rod Pumping Workshop "as is" without any warranty of any kind, express or implied, as to the accuracy of the information or the products or services referred to by any presenter (in so far as such warranties may be excluded under any relevant law) and these members and their companies will not be liable for unlawful actions and any losses or damage that may result from use of any presentation as a consequence of any inaccuracies in, or any omission from, the information which therein may be contained. The views, opinions, and conclusions expressed in these presentations and/or training materials are those of the author and not necessarily those of the Sponsoring Organizations. The author is solely responsible for the content of the materials. The Sponsoring Organizations cannot and do not warrant the accuracy of these documents beyond the source documents, although we do make every attempt to work from authoritative sources. The Sponsoring Organizations provide these presentations and/or training materials as a service. The Sponsoring Organizations make no representations or warranties, express or implied, with respect to the presentations and/or training materials, or any part thereof, including any warrantees of title, non-infringement of copyright or patent rights of others, merchantability, or fitness or suitability for any purpose. 2011 Sucker Rod Pumping Workshop 28