DPL LTD.

Clint Dalziel

Owen Lanktree

Seema Pallan

Replace Sucker rod pump at the well 3-22-21-26W4M near Herronton, Alberta. Based on our comparison of these three pumps

1) Progressive Cavity Pumping System

2) Beam Pump/ Reciprocating Rod Pump

3) Electric Submersible Pumping System

Artificial Oil Lift Technologies-Agenda

3-22-21-26W4MOffsetting Wells

3-22-21-26W4M

Depth 2171m-KB

Reservoir Pressure (May 2007)

1371psig

Bottom hole Temperature ≈ 120oF

Average Daily Fluid Production

≈ 345 STB/Day

Well Information03-22-21-26W4M

Progressive Cavity Pump

Progressive Cavity Pump

Operating Volumes 10BPD – 10,000BPD

Operating Depth 2,000ft to 6,000ft

Operating Temp 75oF – 350oF

Bottomhole pressures -Maximum ≈5000psig

Capital Cost -1/2 of the rod pumping system , 1/5 of an ESP

Efficiency -Excellent, typically 60%-70%

Operating Cost -Low to Moderate

Reliability -Varies-Stator elastomers are sensitive to some well fluids

Progressive Cavity Pump

Travelling

Reciprocating Rod Pump

Reciprocating Rod Pump

Operating Volumes 5BPD-1500 BPD

Operating Depth 100ft -11,000ft

Operating Temp 100oF – 350oF

Bottom hole pressures -50 –100 psig minimum

Capital Cost -Low to moderate, dependant on depth reached

Efficiency -With full pump fillage, around 45%-60% is possible

Operating Cost -Low for depths <7500ft, and production <400 BPD

Reliability -Excellent reliability if good operating practices are followed

Reciprocating Rod Pump

MLE Cable

Submersible Pump

Intake

Protector

Motor

Shaft

HousingDiffuser

Impeller

Electric Submersible Pumps

Electric Submersible Pump

Operating Volumes 200BPD – 30000BPD

Operating Depth 1000ft to 15000ft

Operating Temp 100oF – 400oF

Bottomhole pressures >250psig

Capital Cost -Relatively low if electricity is available, increases with horsepower

Efficiency -Normally around 40%-50%

Operating Cost -High energy cost-High repair cost

Reliability -Sensitive to temperatures and electrical failure.-Short run life

Electric Submersible Pump

Summary of Condition Ranges

Operating Conditions

Pump System

PCP ESP Beam

Operating Volumes 10 –10,000BPD 200 – 30,000BPD 5-1,500 BPD

Depth 2,000ft-6,000ft 1,000ft-15,000ft 100-ft1,100 ft

Pressure <5,000 psig >250 psig >50-100psig

Temperature 75-350oF 100-400oF 100-350oF

Replace the sucker rod system at 3-22-21-26W4M near Herronton Gas Plant

Use the information we were given and our knowledge of the three systems to choose the best system for this well.

Problem

3-22-21-26W4MOffsetting Wells

3-22-21-26W4M

Operating Conditions

Depth 2171m-KB

Reservoir Pressure (May 2007)

1371psig

Bottom hole Temperature ≈ 120oF

Average Daily Production ≈ 345 STB/Day

03-22-21-26W4M Bottomhole Conditions

.

Operating Conditions

Pump System

PCP ESP Beam

Operating Volumes

200 –30000BPD

200 – 30000BPD 5-1500 BPD

Depth 2000ft-6000ft 1000ft-15000ft 100-ft1100 ft

Pressure <5000 psig >250 psig >50-100psig

Temperature 75-350oF 100-400oF 100-350oF

Typical Operating Efficiency

14-22-021-26W4

06-22-021-26W4

04-27-021-26W4

03-22-021-26W4

02-21-21-26W4

0.0

50.0

100.0

150.0

200.0

250.0

Average Total Fluid Production per Day (lifetime)

Well Location

Ave

rag

e T

ota

l F

luid

Pro

dcu

tio

n

(m3/

day

)

14-22-021-26W4

06-22-021-26W4

04-27-021-26W4

03-22-021-26W4

02-21-21-26W4

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

Average Net Oil Production per Day (lifetime)

Well Location

Ave

rag

e P

rod

uct

ion

(m

3/d

ay)

ESP

PCP

RRPRRP

RRP

RRP

PCP

ESPRRP

RRP

Production Comparison

months to payout @

Totals Oil Gas H20 boe's/day 14.2Option # 1 Upsize Rod pump and upsize Pump jack 2 11 58 77.7

Rig time 10,000Pump 8,000Rods Fiberglass/Co-rod 30,000Surface Equip pumpjack 95,000Surface tie-in 10,000

total 153,000 4.6

Option # 2 PCP pump (around the corner) 2 11 58 77.7

Rig time 12,000Pump 16,000Rods 39,000Upsize tbg 10,000Surface Equip 28,000Surface tie-in 10,000

total 115,000 3.5*1854m of coated tbg and couplers 37,000

total 152,000 4.6

Option #2aPCP pump perforation design 20,000

total 119,000 3.6*1854m of coated tbg and couplers 37,000

total 156,000 4.7

Option # 3 ESP (around the corner) 2 11 58 77.7

Rig time 10,000Pump and cable 92,000Surface Equip 43,500Surface tie-in 10,000

total 155,500 4.7

Predicting a Six to Nine month run life??Pump change $70,000

Herronton 3-22-21-26w4

We have decided the more expensive Progressive Cavity system would be the best system to replace the pump on this well with.

Conclusion

The PCP system has: Lower pump cost, which allows us to

replace tubing within the same cost range as an ESP or Rod Pump system.

Lower operating and maintenance cost. Typically higher operating efficiency. High reliability if good operating.

practises are followed. Proven to produce well in this area.

Why?

http://www2.agric.gov.ab.ca/icons/acis/maps/agricultural_land_resource_atlas_of_alberta/overview/township_grid_system_of_alberta/alberta_township_grid_big_map.png

http://www.glossary.oilfield.slb.com/files/OGL05015.gif

http://upload.wikimedia.org/wikipedia/commons/archive/3/3f/20080803011212!Pump_Jack_labelled.png

http://www.weatherford.com

http://www.spe.org/jpt/2009/08/performance-benefits-of-progressing-cavity-pumps-touted/

http://www.glossary.oilfield.slb.com/DisplayImage.cfm?ID=523

Sources