ToughMet 3 TS 95 Sucker Rod Couplings - Materion - A Global … ·  · 2017-12-07Failure...

ToughMet 3 TS 95

Sucker Rod Couplings

©Materion October 2017

2

The costs of working over deviated shale wells operating on artificial lift run into

the hundreds of millions of dollars per year.

Half of the failures in these wells is related to either tubing or sucker rod

coupling failures, caused primarily by wear damage resulting from couplings

contacting the inner tube wall.

The Problem

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Survey of Operators - Well Failures by Type

0

20

40

60

80

100

Year 1 Year 2

%Others

Coupling

Tubing

3Hole in tubing failureToughMet coupling (vertical) with threeConventional couplings after 600 days in service

4

2015 Failure Statistics

5

Measured benefits on > 550 wells indicate when you use ToughMet Couplings you can

1. Eliminate half of all your well failure events

2. Increase your well production at least 6%

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66

“Solution 1” • 20 to 50 couplings in deviated sections only

whether on bottom or near the surface • prevent tubing/coupling wear failures

• Additional investment ~$7,000

“Solution 2” • 150 couplings or more in a much longer section of

the rod string• maximize drag reduction & production increase

• Additional investment ~ $21,000 - $45,000

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The Project

Materion and Hess Corporation collaborated to develop and field

test a new coupling manufactured from ToughMet® 3, Materion’s

high performance, spinodal copper-nickel-tin alloy.

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8

The Project ► Identify and quantify the problem

► Develop a new base material for sucker-rod couplings

► Develop coupling fabrication process

► Produce prototypes using production scale process

► Investigate torque/circumferential displacement and pre-stress behavior relative to existing single and double joint assembly technology to assure attainment of required joint integrity and durability to withstand numerous makes and breaks

► Make modifications to coupling surfaces interfacing with rod

► Validate modifications via additional make and break studies

► Select candidate wells

► Install ToughMet® couplings during workovers

► Evaluate performance at 6 months running

► Evaluate performance at 17 months running

► Evaluate performance at 23 months running

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Selected Trial Wells – Prior experience

► Failure rates ranging mainly from 0.7 to 1.7 per year

► Some failure rates as high as 3 per year

► Failure mode - large majority due to rod and/or tubing wear

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Initial Field Trials► Solution #1 –

10 deviated wells running in Bakken shale locations

Typically 10,000 ft vertical /10,000 ft horizontal

1 inch slim hole ToughMet couplings installed in deviated sections both near-surface and deep

Sweet; range of water cut, sand, brine

Typically 6 pump strokes per minute @ ~ 14-15 feet per stroke

L80 carbon steel production tubing (typical max HRC 22 or 23)

Running with guides and rod rotators

► Solution #2 –

1 well – 1 inch slim hole and ¾ inch full hole ToughMet couplings plus crossover installed in bottom 1,400 feet.

1 well – 1 inch slim hole and ¾ inch full hole ToughMet couplings plus crossover installed in bottom 4,450 feet.

1 well – ¾ inch full in first 1,500 feet of the ¾ inch rod section running slick.

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Results

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Evaluations of “Solution 1”

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Operating Trial Results

► No failures in > 44 months of continuous running; ~ 10.2 million cycles

► 100% of inspected couplings suitable for placement back into service

► Wells continuing to run

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October 1, 2017

14October 1, 2017 14

Original 10 wells - no failures There are now 550 + wells running

GO Biwer 157-98-2635 H1 1313 days

GO Braaten 156-07-3329 H1 1229 days

GO Strahan 15-22 H 1159 days

GO Elvin Garfield 156-97-1819 H1 1321 days

SC Tom 153-98-1514 H4 998 days

SC Tom 153-98-1514 H1 991 days

SC Tom LS153-98-1514 H1 991 days

GN Alice 158-97-1324 H3 960 days

GN EJ 158-97-0706 H1 952 days

GN-Ring-158-98-1522 H1 1081 days

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Example of Significant Run Time Improvement for a Well using 24 ToughMet Couplings

©Materion 201615

This well is still

running. Runtime

increased five-fold

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Couplings

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ToughMet Coupling after 6 Months in Well

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No evidence of wear or metal transfer

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ToughMet Coupling after 6 Months in Well

No evidence of galling of threads

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ToughMet Coupling after 6 Months in Well

No evidence of cracking in thread roots

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ToughMet Couplings after 20 Months in Well

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Evidence of contact between coupling and tubing.

Insignificant wear. No flat spots. No evidence of metal transfer.

Serial numberstill visibleon the coupling

0.010 incheslost from outersurface

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ToughMet Coupling after 20 months in well

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ToughMet Coupling after 20 months in well

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No galling of threads. No evidence of cracking in thread roots

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Tubing

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Operating Trial Results – opportunity to inspect tubing after pump failure on one well

■ History of tubing failures @ ~ 260 days due to coupling wear of the

tubing in bottom ~ 30 joints.

■ ToughMet couplings installed in bottom 650 feet of the well.

■ Well was on line for additional 555 days; went down due to pump

leak.

■ Tubing wall loss and pitting in ToughMet coupling zone much lower

than in SM and T coupling zones.

■ 100% of ToughMet couplings suitable for placement back into

service.

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Tubing Inspection

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1 inch slim ToughMet Couplings; guided rods

¾ inch full Steel Couplings; guided rods

PUMP

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Fewer damaged tubes – ToughMet couplings

Coupling Material SM ToughMet% of tubes having

> 30% wall loss after 555 days 50 0

% of tubes having > 30% surface pitting

after 555 days 25 0

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2727

Reduced tubing damage withToughMet couplings(highest, lowest and mean values are shown)

ToughMet couplings increase MTTF of tubing by at least 3X

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Bakken Well H - Tubing Scan

► New production tubing

► 19 month run time

► 2 red joints- 1 in SM section and 1 in alternating section

SM/ToughMet 3

Alt.

ToughMet 3

SM

Section Depth (ft) Joints

ToughMet (28-1”) 8746-9446 ~292-315

Alternating ToughMet &

SM (120-3/4”)5746-8746 ~192-292

SM 5746 and above ~1-192

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► Lowest average wall loss in ToughMet section

Bakken Well H -Wall Loss by Section

Section Depth (ft) Joints

ToughMet (28-1”) 8746-9446 ~292-315

Alternating

ToughMet & SM

(120-3/4”)

5746-8746 ~192-292

SM5746 and

above~1-192

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► Moving average of wall loss across production tubing

Bakken Well H % Wall Loss Moving Average

SM/ToughMet 3

Alt.

ToughMet 3SM

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► New production tubing

Bakken Well H - Wall Loss/Day

Section Depth (ft) Joints

ToughMet (28-1”) 8746-9446 ~292-315

Alternating

ToughMet & SM

(120-3/4”)

5746-8746 ~192-292

SM5746 and

above~1-192

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► Poly-lined Tubing Run in one well

Well failed due to tubing leak (not in ToughMet section)

ToughMet coupling showed excessive wear

• We know ToughMet does not run well against polymers

• Extensive investment in poly-lined tubing not required

• We recommend most cost effective solution is combination of ToughMetcouplings with steel tubing

► Boronized Tubing ToughMet couplings are running in approximately 10 wells

• Feedback from the field is positive

• One well running 40 couplings had 2 couplings that showed wear 2 feet and 52 feet above the pump.

- Couplings in MTRN lab for evaluation

Production Tubing

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Eliminate tubing and coupling failuresEliminate half of all your well failure events

What’s it worth?

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Calculation of Financial Value per Well per Yearby eliminating tubing and coupling failures

Frequency of well failure (x/yr) 0.7 to 1.7

Proportion due to targeted cause 0.5

Failure prevention rate 0.35 to 0.85

Work over cost $100,000 - $150,000

Workover cost avoided (range) $35,000 - $127,500

Workover cost avoided (probable) $75,000

Marginal cost of 50 ToughMet couplings/crossover

($7,000)

Additional well production (10 days @ 100 bbl/day @ $40/bbl)

$40,000

Total additional cash flow (range) $90,000 to $182,500

Total additional cash flow (probable) $110,000

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“Solution 2” Evaluations

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Operating Trial Results

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► Well production increases► Overall system drag decreases significantly► Pump stroke increases significantly► Rod string moves “more smoothly”► System mechanical loads decrease significantly

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“Solution 2”3 wells running 50 to 200 ToughMet Couplings

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It is possible to significantly reduce over-all frictional losses of the system.

SM Coupling

T Coupling

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1st New Operating Trial – 55 ToughMet couplings

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• ToughMet couplings installed in bottom 1,400 ft section.• 24 each ¾” Full; 31 each 1” Slim on bottom; one crossover.• Guided

Rod/couplingdrag

coefficient

Prior Standard Practice

0.2

ToughMethypothesis

0.1

ToughMethypothesis

0.05

ToughMet Actual

0.035

Pump stroke-in.

141 146 148 151

Liquid production-

bpd233 240 (3%) 243 (4%) 248 (6.5%)

Polished rod load-pounds

33,000 32,500 32,200 31,570

Gear box max design

load exceedance %

5 3 1 minus 2

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EN-L Cvancara Well Oil Production Rates-Pre and Post Workover This is an example showing stabilized production increase of 9% after installing

55 ToughMet couplings. Actual results confirm theoretical expectations for < 0.035 drag coefficient hypothesis.

Results reported by other operators meet or exceed this example.

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©Materion 201540*Data after well stabilized. Same pump size pre and post ToughMet Couplings

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2nd New operating trial – 176 ToughMet couplings

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• ToughMet couplings installed in bottom 4,450 ft section.• 124 each ¾” Full, no guides; then 24 each ¾” Full, guided ; • 28 each 1” Slim, guided on bottom; one crossover.

Prior performance

ToughMet performance

Pump StrokeUP 24%

*Data after well stabilized. Same pump size pre and post ToughMet Couplings

4242

Comparative card from another operator after installing ToughMet couplings in bottom 40 joints. Max load decreased 12%. Pump stroke increased 21%

*Comparative data after well stabilized. Same pump size pre and post ToughMet couplings

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Combined Financial Results Eliminate tubing and coupling failures.

Increase well production.What’s it worth?

Measured results indicate ToughMet 3 Sucker Rod Couplings mitigate

the most common cause of deviated well failure thereby statistically

reducing workover costs by $75,000 per well per year (net).

Results also indicate ToughMet 3 Sucker Rod Couplings reduce overall system

friction, increasing well production by as much as 6 to 15%.

The net benefit to a well producing 100 barrels of oil per day

at $20 / bbl (net) is

$140,000 to 185,000 of pre-tax cash flow per year.

The return on investment is high and the payback is quick.

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Coupling Material Technology

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High-strength, non-galling oilfield material with more than 20 years successful

use in oilfield equipment components.

► > 2 million pounds per year

► Mainly directional drilling, MWD, LWD and rotary steerable tools

ToughMet® 3Heat-treatable UNS C72900 Cu15Ni8Sn alloy

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ToughMet Oilfield Applications continued…

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Hydraulic control fluid connections ESP motor bearings

Tri-cone drill bit bearings and thrust washers

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ToughMet® 3 TS 95 Material

Cu15Ni8Sn spinodal alloy

- > 95 ksi yield strength

- Hardness HRB 93 to 97 (~HRC 20)

- Anti-galling to typical steel production tubing and sucker rods

Property upgrades to provide ideal material for couplings

• Increased fracture & impact toughness

- > 30 ft-lb Charpy Impact Energy

• Increased fatigue strength

- ~ 40 ksi fatigue limit

Corrosion Reisistance

- Resistant to CO2 corrosion

- Resistant to chloride SCC, pitting and crevice corrosion

- Resistant to erosion, HE, SSC and general corrosion (including in mildly sour wells)

Dimensions conform to API 11B

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4848

Tribology - ToughMet® 3

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Tribology – Metal-on-Metal Wear

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0.045

0.050

0 30 60 90 120 150 180

Hardened Steel

Aluminum Bronze

ToughMet 3

Cycles (000’s)

Clearance

Increase

Due

to Wear

(inches)

Oscillating axial motion with side loading. Average bearing stress @ 2,000 psi. Carburized steel shaft.

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Bearing Material

5050

Sour Service Considerations• Environments having hydrogen sulfide > 0.05 psia partial pressure

are considered “sour.”

• NACE MRO175/ISO 15156 standards allow unrestricted use of copper based alloys• Sulfide stress cracking (SSC) is not observed• General weight loss corrosion occurs depending on the

the partial pressure of hydrogen sulfide and temperature

• We know that • SSC may occur in copper alloys if the hydrogen sulfide partial pressure is

• > 100 psi• 14.7 psi @ room temperature

• We recommend • 20 psi hydrogen sulfide partial pressure

upper limit for ToughMet couplings• 37 deg F > Operating Temperature < 300 deg F

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Environment pH pp H2S

psi

pp CO2

psi

NaCl

%

Temp

deg C

Weight

Loss

0.001

inch/year

Production ~3 1200 400 25 175 huge

Production

(NACE VII)

~3 508 508 25 205 137

Production ~4 580 189 15 90 117

Production ~5 568 237 8 100 32

Production (NACE V) ~3 101 203 15 150 4 to 22

Production ~5 5 200 25 150 12

Production ~3 5 200 25 95 1 to 3

Production

(NACE IV)

~3 0.43 101 15 90 1

Production

(NACE II)

~3 14.7 - 5 23 1

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Sour Service – ToughMet 3 Weight Loss

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Temperatures range from 80 -150 degrees Celsius

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Temperatures range from 80 -150 degrees Celsius

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Effect of Hydrogen Sulfide Concentration on Weight Loss Corrosion Rate of ToughMet 3 TS Temper@ temperature > 100 degrees C

y = 0.266x - 0.9876R² = 0.9787

0

20

40

60

80

100

120

140

160

0 100 200 300 400 500 600

0.001 inchper year

Partial Pressure psi

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Couplings from Seminole Field Well Failure

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Seminole Field Sour Well Trial

► One deviated well; historical 1.5 failure/year due to target cause

► 5000 feet vertical► 110 deg F bottom; 90 deg F well head► 28 % CO2 ( ~ 630 psi pp)► 7 % H2S ( ~ 160 psi pp)► J55 carbon steel tubing – NACE► High strength rod► ToughMet 7/8 and 3/4 couplings installed in bottom 1500

feet► This well failed after three months run time with ToughMet

couplings. Failure was due to rod parting.► The couplings were damaged by “tribo-corrosion.” The

damage was increased because the rod rotator stopped working.

5757

Analysis of expected behavior of a ToughMet coupling operating in a sour shale well

• 10,000 feet depth, 220 degrees F temp on bottom• Production tubing ID ~ 2.44 inches• Rod string OD ~ 0.75 to 1 inch• ~500,000 to 450,000 cu-in fluids• @ 231 cu-in/gal = 2100 gal fluids• Brine density 9.6 lb/gal• Total hydrostatic load = ~ 20,000 lb• Hydrostatic pressure above pump = ~ 4,300 psi• Partial pressure of hydrogen sulfide at 4,600 ppm (0.46%) ~ 20 psi• Expected radial loss of ToughMet 3 coupling after 5 years ~ 0.022 in. • Change in stress-bearing capability of 1 inch coupling ~ 5 %

5858

Chemical Additive CompatibilityLab testing and field experience indicate ToughMet couplings are compatible

with commonly-used well treatment chemicals and practices.

Nalco Baker

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N=20 Study of coupling make & break behavior

Coupling 1st Makeup Stable Makeup 1st Makeup Stable Makeup

Stress slope psi/inch CD

Stress slope psi/inch CD

Peak Torqueft-lb

Peak Torqueft-lb

T 110,000 94,000 1,700 1,200

ToughMet 102,000 92,000 1,800 1,340

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Coupling Pin stresspsi (m)

Pin stresspsi (s)

CDm

CDs

Singles

T 53,333 5,774 65 2

ToughMet 50,286 7,868 66 3

Doubles

T 52,500 9,574 68 1

ToughMet 50,000 5,774 69 0

1 inch grade 78 rods 48 RPM TOPCO SRL lubricantA “Smart Tong” was used to make and break the joints

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Comparison of T-Coupling, Spraymetal and ToughMet 3TS-95

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T-coupling Spray Metal ToughMet 3TS-95

Surface Finish 125RMS in µ-in. 63 RMS in µ-in. 125RMS in µ-in.

End Finish 125RMS in µ-in. 125RMS in µ-in. 250 RMS in µ-in.

Hardness 16-23 HRC 55-60 HRC 20 HRC

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Controlled Makeup/Breakout Tests at Key Energy Services

6262

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You can use your existing practices to install ToughMet couplings

► When making up either single or double coupling-to-rod connections, you may use standard circumferential displacement cards which are proscribed by rod manufacturers for the type of rod you are using. Modifications made to ToughMet couplings

• Surface finish modifications to shoulder faces• Copper flash on ID

► You can identify used ToughMet couplings by using a permanent magnet. ToughMet couplings are non-magnetic and non-sparking.

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New-ToughMetRod Lift Application

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ToughMet 3 TS95Valve Rod Guide Bushing Coupling

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We also producea tapered coupling for connecting

the rod string to the pump drive rod

ToughMet VRGB Coupling was developed byHess and Materion to act as a centralizer to prevent the valve rod bushing from wearing out the adjacent tubing.

The tapered coupling has a 2 inch OD with ¾ inch rolled threads.

It is installed on top of the Valve Rod bushing.

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►Questions?

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POCKET SLIDES

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Sucker Rods and Couplings

couplings

682 M wells in operation, 1 M on artificial lift, 750K on rod pump

6969

Production Applications –Electric Submersible Pumps & Motors

ToughMet motor bearings replace cobalt 6

ToughMet shaft couplings replace K500 and steel

ToughMet motor bearingsafter full life cycle test in

The field

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ToughMet´s Spinodal Nanostructure

• Strengthening by spontaneous decomposition on the nanostructuralscale into alternating waves of hard and soft phases

• Phases are chemically different but identical in crystalline structure

• Hard and soft phases still exist

- Dark = hard Ni3Sn

- Light = softer Cu – 15 % Ni

- Submicroscopic

- Highly uniform distribution

• Microscopic asperities on mating surface “see” microscopically smooth ToughMet = lower friction

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ToughMet 3 CX105 >300,000 X

electron microphotograph of

spinodal structure