Download - Experience Rod Pumping Deviated CBM Wells - ALRDC · 7th Annual Sucker Rod Pumping ... Oklahoma City, Oklahoma September 27 - 30, 2011 Experience Rod Pumping Deviated CBM Wells

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



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


“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



• 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.



• 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.



• 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



• “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

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2

4

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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



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


0

2

4

6

8

10

12

14

0 100 200 300 400 500

Side Load, Pounds

Run

Tim

e, R

unni

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Yea

rs



“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



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.



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’


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.



“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


0

2

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14

0 100 200 300 400 500

Side Load, Pounds

Run

Tim

e, R

unni

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ime,

Yea

rs




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


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




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


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 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


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 poly-tubing.

Sidetrack


Friction and Wear Reduction Runtime Improvement – Poly Lined Tubing Repeat Failure Wells

Well A • Previous Average Runtime - 273 Days (13 Failures- 9

Wear) • Average Poly Runtime - 650 Days (1 Failure- Not Wear) • Current Poly Running Time - 167 Days

Well B • Previous Average Runtime - 679 Days (3 Failures- 1 Wear) • Current Poly Running Time – 1,212 Days

Well C (Sidetrack) • Previous Average Runtime - 313 Days (10 Failures- 5 Wear) • Poly Running Time - 427 Days

“S” Well Well D

• Previous Average Runtime - 84 Days (2 Failures- 1 Wear) • Current Poly Running Time – 1,079 Days


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).

S Well with Rod Guides

Installation Date

Dynamometer Card

Date

Months run before

Dynamometer

RODSTAR Coefficient

SROD Coefficient

Well 1 9/10/2007 11/14/2007 2 0.40 0.40Well 2 9/25/2007 5/12/2008 8 0.25 0.25Well 3 4/4/2008 11/14/2008 7 0.20 0.18Well 4 2/17/2009 4/28/2009 2 0.34 0.38Well 5 10/9/2007 2/23/2010 29 0.31 0.29Well 6 8/9/2006 2/19/2010 43 0.29 0.34Well 7 7/28/2008 9/8/2009 14 0.20 0.21Well 8 11/21/2005 8/10/2009 45 0.25 0.27Well 9 8/19/2005 12/17/2009 53 0.31 0.32Well 10 5/13/2004 3/26/2009 59 0.20 0.20Well 11 7/14/2006 6/25/2009 36 0.16 0.19Average 0.26 0.28


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.

Friction and Wear Reduction

Poly-lined Tubing "S" Wells

Installation Date Card Date

Months run before

Dynamometer

RODSTAR Coefficient

SROD Coefficient

Well 12 1/19/2009 9/28/2009 8 0.15 0.16Well 13 8/25/2008 10/14/2009 14 0.02 0.04Well 14 3/1/2008 9/28/2009 19 0.10 0.07Well 15 6/4/2008 9/17/2009 16 0.07 0.10Average 0.09 0.09


“S” Well Failure Trend

Failure rates steady since program started, with 2010 a very good year.


Failure Trend

“S” Well Failure Rate • 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.

"S" Well Failure Trend

0.00

0.10

0.20

0.30

0.40

0.50

0.60

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Failu

res

per W

ell p

er Y

ear


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.



Questions?


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Download - Experience Rod Pumping Deviated CBM Wells - ALRDC · 7th Annual Sucker Rod Pumping ... Oklahoma City, Oklahoma September 27 - 30, 2011 Experience Rod Pumping Deviated CBM Wells

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