Proven Production Benefits From Slippage-Filtering Sand ... · production plunger Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop. STP Pump Operation - Upstroke Slide 18 • At

13th Annual Sucker Rod Pumping

WorkshopRenaissance Hotel

Oklahoma City, Oklahoma

September 12 – 15, 2017

Proven Production Benefits From Slippage-Filtering Sand Tolerant Pump

John StachowiakDoug Hebert

Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop

Pump Geometry and Operation - Upstroke

Slide 2

2

upstroke

Barrel

Plunger

Travelling

valve

Standing

valve

High Pressure

Low Pressure

What happens when

sand is present in the

fluid on the upstroke?


Conventional insert pump


Slide 3

3

upstroke

Barrel

Plunger

Travelling

valve

Standing

valve

High Pressure

Low Pressure

What happens when

sand is present in the

fluid on the upstroke?


Conventional insert pump

Pressure

Differential

Pump Geometry and Operation – Upstroke

Slide 4

4

Barrel

Sli

pp

ag

e f

luid

Sli

pp

ag

e f

luid

Plunger

• On the upstroke, the differential pressure drives the sand-laden slippage fluid between the plunger and barrel.

Sand particle Plunger leading

edge



Slide 5

Barrel Slip

page f

luid

Slip

page f

luid

Plunger

Sand particle

Plunger leading

edge

…a closer look

5Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop


Slide 6

6

Plunger/barrel

clearance

Sand particle

diameter Smaller sand particles can pass through the plunger/barrel interface easily with little to no damage.


Slide 7

Pump Operation With Sand - Upstroke

7

Barrel

Slip

pa

ge

flu

id

Plunger

• When a larger particle cannot easily pass by the plunger it becomes lodged.

Large sand particle

Slip

pa

ge

flu

id



Slide 8

8

Slippage fluid

hydrostatic load

A groove is

created in

plunger or barrel

• The upward plunger motion along with the hydrostatic load assists to drive the hard sand particle between the plunger and barrel, causing a small groove.

Plunger motion



Slide 9

9

Slippage fluid

hydrostatic load

• On the next upstroke, more large particles can now follow the same path, creating a longer groove.

Plunger motionGro

ove L

en

gth


Pump Operation With Sand – Plunger Grooving

Slide 10

10

• This process continues until the groove is extended the entire length of the plunger and/or the swept length of the barrel


Slide 11

Pump Operation With Sand – Plunger grooving

11

• This process continues until the groove is extended the entire length of the plunger and/or the length of the swept length of the barrel

• As more grooves are created, the plunger becomes extremely inefficient as more fluid is lost from slippage on the upstroke

• As more grooves are created, the plunger becomes extremely inefficient as more fluid is lost from slippage on the upstroke


Slide 12

STP Pump - Overview

12

New Sand Tolerant Pump

(STP) Technology With

Integral ScreenBarrel

Plunger Travelling

valve

Standing

valve

Sand

control

region

Tubing


STP Pump - Overview

Slide 13

13

Ring

MandrelFilter

Screen

Wiping

Rings

Production

Plunger


STP Pump Operation - Upstroke

Slide 14

14

Upstroke

Barrel

Plunger

Travelling

valve

Standing

valve

High Pressure

Low Pressure



Slide 15

15

High Pressure

• On the upstroke, the wiper rings are pressure balanced.

• The wiper rings do not see the differential hydrostatic load – No lifting edge

High Pressure

Wiper

rings

Filter

Screen


Slide 16


16

Upstroke Slippage fluidSlippage fluid

• Wiper rings act as

fluid/sand barrier

• All of the slippage

fluid is forced

through the screen



Slide 17

17

UpstrokeScreen

• The screen is sized to

only allow particles to

pass through that are

smaller than the radial

clearance “fit” of the

production plunger



Slide 18

• At the top of the plunger

upstroke, there may be

many particles that have

accumulated on the

inside of the screen.

Particles trapped

by screen

Upstroke

Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 18

STP Pump Operation - Downstroke

Slide 19

19

Barrel

Plunger

Travelling

valve

Standing

valve

High Pressure

High Pressure

• The pressure is

equalized above and

below the plunger

On the downstroke….


Slide 20


20

…The flow of slippage

fluid stops

•Trapped Particles

become looseNo

flow

across

screen

On the downstroke….


Slide 21


21

Downstroke

• The fluid rushes up

through the inside of

the plunger assembly,

and washes the

screen clean


Slide 22

22

• For field trial #1, the goal was to concentrate strictly on

runtime comparison between conventional and STP

pumps.

• High sand-producing wells with a history of short run

times were selected for the trial.

➢ Selected wells achieved less than one year on

previous two pump run times.


Field Trial #1 – Conventional vs STP

- Parameters

Slide 23

23

Pump parameters:



- Parameters

• Pump size varied

• 1 ¼” bore – 24 pumps

• 1 ½” bore – 17 pumps

• 1 ¾” bore – 10 pumps

• 2” bore – 6 pumps

• .005-.006 plunger fit

• 6-7 strokes per minute

Well parameters:

• ~150 F Downhole temp

• Light to heavy crude

• 30-95% water cut

• High sand content

• 3000-9000 ft depth

• 56 wells were chosen to track that met the parameters.

• Data was captured for three subsequent pump

installations in each well.

Two conventional pumps

One STP

Slide 24


Field Trial #1 Results – Conventional vs STP

Slide 25

25

• For field trial #2, the goal was to take a closer look at

efficiency/production loss due to plunger wear.

• Steam injected wells with a history of severe sand wear

and short run life (less than one year on average) were

selected.

Pump parameters:



- Parameters

• 2 ¼ bore insert pump

• - .012 plunger clearance

• Due to the large sand

particles

Well parameters:

• 250 – 350 F Downhole temp

• 16 API gravity oil

• 70-95% water cut

• High sand content

• 3300 ft depth

Slide 26

26

• Data was captured and analyzed in three of these wells.

As with Trial #1, each STP will be compared with the

previous two conventional pumps.

• Well “A”

• Well “B”

• Well “C



- Parameters

• These 3 wells will be presented

27


- Background


Typical plunger failures in these

wells

218 Days

169 Days

28

Spray metal coating 56 Rc

Base metal22 Rc


- Background

Plunger cross section


29

Plunger cross section

Wear area

The total wear area equates to a -.036 fit plunger!

Original surface


- Background


30


- Background


0

200

400

600

800

1000

1200

0.012 0.014 0.016 0.018 0.02 0.022 0.024 0.026 0.028 0.03 0.032 0.034 0.036

Ba

rre

ls o

f F

luid

Pe

r D

ay

Pump Clearance Between Plunger and Barrel - inch

100% Pump Efficiency vs Slippage (Patterson Equation) Plunger Diameter = 2.25

5.00 6.00 7.00 8.00 9.00 10.00SPM

10

0%

eff

icie

ncy

Slip

pag

e

31


- Background


0

200

400

600

800

1000

1200

0.012 0.014 0.016 0.018 0.02 0.022 0.024 0.026 0.028 0.03 0.032 0.034 0.036

Ba

rre

ls o

f F

luid

Pe

r D

ay



5.00 6.00 7.00 8.00 9.00 10.00SPM

10

0%

eff

icie

ncy

Slip

pag

e

.012 Clearance86% Max efficient

cProduction @ 5 SPM

.036 Clearance25% Max efficient

c

32


- Background


0

200

400

600

800

1000

1200

0.012 0.014 0.016 0.018 0.02 0.022 0.024 0.026 0.028 0.03 0.032 0.034 0.036

Ba

rre

ls o

f F

luid

Pe

r D

ay



5.00 6.00 7.00 8.00 9.00 10.00SPM

10

0%

eff

icie

ncy

Slip

pag

e

.036 Clearance 47% Max efficient

.012 Clearance 90% Max efficient

Production @ 10 SPM

33

Field Trial #2 – Conventional vs STP – Well “A”

0

2

4

6

8

10

12

0

200

400

600

800

1000

1200

0

25

50

75

10

0

12

5

15

0

17

5

15

40

65

90

11

5

14

0

16

5

19

0

17

42

67

92

11

7

14

2

16

7

19

2

21

7

24

2

26

7

29

2

31

7

34

2

36

7

39

2

41

7

44

2

46

7

49

2

51

7

54

2

Bar

rels

Pe

r D

ay

Run Life (Days)

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

184 Days 197 Days 560 Days

Actual ProductionActual Production


34


0

2

4

6

8

10

0

200

400

600

800

1000

1200

0

25

50

75

10

0

12

5

15

0

17

5

15

40

65

90

11

5

14

0

16

5

19

0

17

42

67

92

11

7

14

2

16

7

19

2

21

7

24

2

26

7

29

2

31

7

34

2

36

7

39

2

41

7

44

2

46

7

49

2

51

7

54

2

Bar

rels

Pe

r D

ay

Run Life (Days)

Stro

kes

Pe

r M

inu

te

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


Maximum SPM

Actual ProductionMax Potential Production & SPMActual Production


35


0

2

4

6

8

10

0

200

400

600

800

1000

1200

0

25

50

75

10

0

12

5

15

0

17

5

15

40

65

90

11

5

14

0

16

5

19

0

17

42

67

92

11

7

14

2

16

7

19

2

21

7

24

2

26

7

29

2

31

7

34

2

36

7

39

2

41

7

44

2

46

7

49

2

51

7

54

2

Bar

rels

Pe

r D

ay

Run Life (Days)

Stro

kes

Pe

r M

inu

te

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


Maximum SPM

Actual ProductionMax Potential Production & SPM InefficiencyActual Production


36


0

2

4

6

8

10

0

200

400

600

800

1000

1200

0

25

50

75

10

0

12

5

15

0

17

5

15

40

65

90

11

5

14

0

16

5

19

0

17

42

67

92

11

7

14

2

16

7

19

2

21

7

24

2

26

7

29

2

31

7

34

2

36

7

39

2

41

7

44

2

46

7

49

2

51

7

54

2

Bar

rels

Pe

r D

ay

Run Life (Days)

Stro

kes

Pe

r M

inu

te

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


Maximum SPM

Production decline and higher SPMIndication of Slippage



Efficiency maintained through 400 days

0

2

4

6

8

10

0

200

400

600

800

1000

12002

9

59

89

11

9

14

9

17

9

20

9

23

9

26

9

29

9

32

9

35

9

38

9

17

47

77

10

7

13

7

14

44

74

10

4

13

4

16

4

19

4

22

4

25

4

28

4

31

4

34

4

37

4

40

4

43

4

46

4

49

4

52

4

55

4

37

Field Trial #2 – Conventional vs STP – Well “B”

”

Bar

rels

Pe

r D

ay

Run Life (Days)



Stro

kes

Pe

r M

inu

te

Co

nve

nti

on

al

STP

Co

nve

nti

on

al


0

2

4

6

8

10

0

200

400

600

800

1000

12002

9

59

89

11

9

14

9

17

9

20

9

23

9

26

9

29

9

32

9

35

9

38

9

17

47

77

10

7

13

7

14

44

74

10

4

13

4

16

4

19

4

22

4

25

4

28

4

31

4

34

4

37

4

40

4

43

4

46

4

49

4

52

4

55

4

38


”

Bar

rels

Pe

r D

ay

Run Life (Days)



Maximum SPM

Stro

kes

Pe

r M

inu

te

Co

nve

nti

on

al

STP

Co

nve

nti

on

al


0

2

4

6

8

10

0

200

400

600

800

1000

12002

9

59

89

11

9

14

9

17

9

20

9

23

9

26

9

29

9

32

9

35

9

38

9

17

47

77

10

7

13

7

14

44

74

10

4

13

4

16

4

19

4

22

4

25

4

28

4

31

4

34

4

37

4

40

4

43

4

46

4

49

4

52

4

55

4

39


”

Bar

rels

Pe

r D

ay

Run Life (Days)



Maximum SPM

Stro

kes

Pe

r M

inu

te

Co

nve

nti

on

al

STP

Efficiency Decrease

Co

nve

nti

on

alEfficiency Maintained


Efficiency Decrease

40

Field Trial #2 – Conventional vs STP – Well “C”B

arre

ls P

er

Day

Run Life (Days)

Co

nve

nti

on

al

Co

nve

nti

on

al

0

2

4

6

8

10

12

0

200

400

600

800

1000

0

30

60

90

12

0

15

0

18

0

16

46

76

10

6

13

6

16

6

19

6

22

6

25

6

28

6

31

6

34

6

37

6

40

6

11

41

71

10

1

13

1

16

1

19

1

22

1

25

1

28

1

31

1

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


Actual ProductionActual Production


41


arre

ls P

er

Day

Run Life (Days)

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

0

2

4

6

8

10

12

0

200

400

600

800

1000

0

30

60

90

12

0

15

0

18

0

16

46

76

10

6

13

6

16

6

19

6

22

6

25

6

28

6

31

6

34

6

37

6

40

6

11

41

71

10

1

13

1

16

1

19

1

22

1

25

1

28

1

31

1

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


Maximum SPM

Stro

kes

Pe

r M

inu

te



42


arre

ls P

er

Day

Run Life (Days)

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

0

2

4

6

8

10

12

0

200

400

600

800

1000

0

30

60

90

12

0

15

0

18

0

16

46

76

10

6

13

6

16

6

19

6

22

6

25

6

28

6

31

6

34

6

37

6

40

6

11

41

71

10

1

13

1

16

1

19

1

22

1

25

1

28

1

31

1

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


Maximum SPM

Stro

kes

Pe

r M

inu

te


Efficiency Decrease

Efficiency Decrease

Efficiency Maintained


43

Field Trial #2 – Conventional vs STP – SummarySt

roke

s/M

in

4

5

6

7

8

9

10Average Strokes/Min+

22

%

+ 1

3 %

+ 4

6 %

+ 3

4 %

+ 5

6 %

+ 5

1 %

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

Well “A” Well “B” Well “C”

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


44


roke

s P

er

Bar

rel

12

15

18

21

24

27

30

33

36

39

42

45

48

"A" STP

"A" C

on

v 1

"A" C

on

v 2

"B" STP

"B" C

on

v 1

"B" C

on

v 2

"C" STP

"C" C

on

v 1

"C" C

on

v 2

Average Strokes/Barrel

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


+ 4

9%

+ 1

1%

+ 1

11

%

+ 6

3% +

5 %

+ 4

6%


45


roke

s P

er

Bar

rel

12

15

18

21

24

27

30

33

36

39

42

45

48

"A" STP

"A" C

on

v 1

"A" C

on

v 2

"B" STP

"B" C

on

v 1

"B" C

on

v 2

"C" STP

"C" C

on

v 1

"C" C

on

v 2

Average Strokes/Barrel

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

Co

nve

nti

on

al

Co

nve

nti

on

al

STP

Co

nve

nti

on

al

Co

nve

nti

on

al

STP


+ 4

9%

+ 1

1%

+ 1

11

%

+ 6

3% +

5 %

+ 4

6%


• Greater Operating Expense• Wear and Tear on equipment• Higher Energy Costs• Intervention Frequency


Questions?

Copyright

47

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.


Disclaimer

48

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.


Proven Production Benefits From Slippage-Filtering Sand ... · production plunger Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop. STP Pump Operation - Upstroke Slide 18 • At

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