ENHANCE PERFORMANCE & EXTENDRUN LIFE OF ROD PUMPED WELLS

WITH SPECIALTY COUPLING ALLOY

1

2019 PERMIAN ARTIFICIAL LIFT CONFERENCE

THE PROBLEM

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▶ Workover costs of deviated shale wells operating on artificial lift run into hundreds of millions of dollars per year

▶ High failure rates due to tubing or coupling failures

Survey of Operators-Failures by Type

Tubing Coupling Others

Spray Metal TTubing Wear High Med

Coupling Wear Low High

TOUGHMET® 3 ALLOY

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▶ Advanced bearing material used in O&G for > 20 years—High strength—Anti-galling—Low elastic modulus—Low coefficient of friction—Corrosion resistant

▶ Cu-Ni15-Sn8

SOLUTION 1

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SOLUTION 1: EXTEND RUN LIFE

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▶ “Solution 1” uses 20-60 ToughMet couplings in deviated sections

▶ Reduces tubing wear over standard coupling materials

ToughMet Spray Metal T

Tubing Wear Low High Med

Coupling Wear Med Low High

Friction Low High High

Coated on OD No Yes No

J55 WEAR TESTING

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▶ J55 tubing wear rates—SM wore tubing 3X’s faster than ToughMet—T wore tubing 2X’s faster than ToughMet

Severe deformation to T coupling

Low Load Test

1.E-14

1.E-13

1.E-12

0 500 1000 1500 2000

Spec

ific

Wea

r Rat

e (1

/psi

)Contact Stress (psi)

J55 WearSM T ToughMet

J55 Coupling Material

90 lbs

100 RPM

48 hrtest Mineral oil

COUPLING EFFECT ON TUBING WEAR IN FIELD

1” slim ToughMet;

guided

¾” fullSM;

guided

Coupling Material SM ToughMet

% of joints having > 30% wall loss 50 0

% of joints having > 30% surface pitting 25 0

▶ Failure History: 260 days due to tubing leaks in bottom 30 joints

▶ Run time: 555 days (pump failure)

MTTF OF TUBING INCREASED BY AT LEAST 3X

8

0

0.005

0.01

0.015

0.02

0.025

0.03

Spray Metal ToughMet

% WALL LOSS/DAY

MaxMinAvg

COUPLING EFFECT ON TUBING RUN TIME

9

!"#$%& '"% !$() = !"#$%& +,$-".) /,0) − !"#$%& 2%30,-- /,0)▶ Recorded the min and median tubing run times for:—1) Before ToughMet, 2) after ToughMet, 3) and not yet failed

with ToughMet

Before After Not Yet Failed

Other Failure

ToughMet/ Tubing Install

Tubing Install HIT HIT

Tubing Install

CASE STUDY: EJH4 WELL (BAKKEN)

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▶ Tubing life improvement: 272 days or +196%

Before After139 days (minimum)197 days (median) 411 days

Not Yet Failed assessed Feb 2018

0

100

200

300

400

0 100 200 300 400

Tubi

ng R

un T

ime-

Toug

hMet

(day

s)

Tubing Run Time- Spray Metal (days)

Tubing Run Time: Before & After ToughMet

After_Min After_Med x=y

▶ 24- ¾” full and 31- 1” slim ToughMet couplings installed on bottom of rod string

▶ Guided, 2-7/8 L80, 6 SPM, 168” Stroke, ~10,000 ft deep horizontal

Before w/ Spray Metal:

111 Days

After w/ ToughMet:340 Days

Not Yet Failed:787 Days as of

12/27/2018

Polished Rod Failure after 711 Days; No Tubing Replaced

ToughMet/New Tubing Install

Tubing Install

HIT HIT New Tubing Install

CASE STUDY: CVH3 WELL (BAKKEN)

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Avoided 3 Workovers

Avg.

Avoided 7 Workovers and Still Running

▶ Replaced 230 T couplings with ToughMet (216 7/8” full; 18 1” slim; 1 VRGB)

▶ Guided, J55, Steel Rods, 7 SPM, 144” Stroke, ~5900 ft deep horizontal, 12deg/100 ft DLS

Before w/ T:76 Days (Avg.)

Not Yet Failed:282 Days as of 1/2/2019

+271%

ToughMetInstall

Install Failure

CASE STUDY: CB16 WELL (PERMIAN)

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Avoided 3.7 Workovers and Still Running

AVERAGE COUPLING EFFECT ON TUBING LIFE ACROSS LARGE DATA SET

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▶ 62% avg increase in tubing run time after ToughMet install—50 wells —Failure rate: 300 days or

less due to tubing leaks—# ToughMet couplings: 12-

40 in bottom of rod string

213, Spray Metal

341,T3

180

220

260

300

340

380

420

Tubi

ng R

un T

ime

(Day

s)

95% CI for the Mean

Before After

AVERAGE COUPLING EFFECT ON OVERALL RUN TIME

▶ Initial 40 well pilot with Hess—ToughMet couplings installed in

problematic sections—No other major design changes

▶ Average run time with spray metal ~200 days

▶ Average run time with ToughMet~365 days 85% improvement

▶ Hess has since installed ToughMetcouplings in > 800 wells

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200, Spray Metal

365, T3

180

220

260

300

340

380

420

Run

Tim

e (D

ays)

ToughMet Effect on Run Time Across Initial 40 wells

Before After

SOLUTION 2

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SOLUTION 2: IMPROVE WELL EFFICIENCY

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▶ “Solution 2” uses 150+ ToughMet couplings in a large section of the rod string

▶ Reduces sliding friction on the rod string and loading

▶ Improves sucker rod string movement, productivity, and efficiency

▶ Plus*** the benefits of Solution 1

ToughMet Spray Metal T

Tubing Wear

Low High Med

Coupling Wear Med Low High

Friction Low High High

Coated on OD No Yes No

DRY SLIDING FRICTION OF MATERIALS IN CONTACT WITH CARBON STEEL

0.70.6

0.17

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Nickel Alloy Carbon Steel ToughMet

Friction Coefficient

Spray Metal 60 HRC

T16-23 HRC

ToughMet20+ HRC

SOLUTION 2 TRIALS

▶Pilot designed to measure effect of ToughMet couplings on well performance—22 full strings —5 large partials—14 major operators—Permian, Bakken, West Coast

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EFFECT OF REDUCED FRICTION ON THE SUCKER ROD STRING

▶Sucker rod string movement is smoother- less drag on up and down stroke

▶Effects:↓ Loads (Gearbox & Polished Rod)↑ Efficiency↑ Fluid production↑ Downhole stroke↑ Pump fillage↓ Fluid level

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PERMIAN FULL STRING

Shale Play PermianType Full StringInstall Date Aug 2017

Run Time 17.2 months

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Well DetailsToughMet Couplings 186 (replaced SM+T)Pump Size 1.75”Pump Set Depth 6656 ft. (set in curve)Tubing L80Rods Fiberglass/SteelSPM 7 (VSD)Designed Stroke Length 130”Side Loads/Dog Leg Sev 240 lbs/1.84 at SNRotators Rod/Tubing RotatorsGuides Yes

PERMIAN FULL STRING

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Before:6-7 Months

Rod Parts/Tubing1.85 FPY

Not Yet Failed:17.2+ Months

<0.70 FPY

ToughMetInstall

Install Failure

Avoided 2.6 Workovers and Still Running

PERMIAN FULL STRING

Before ToughMet

After ToughMet

Change % Change

Oil (bpd) 110 130.5 20.5 19% ↑Gas (mscfpd) 186 144 -48 -22% -

Water (bpd) 124 127 3 2% -

DH Stroke (in) 132.0 154.3 21.3 17% ↑Fluid Level AP (ft) 1590 1096 -494 -31% ↓Pump Fillage 90% 97% 7% 7% ↑Gear Box Loading 84% 65% -19% -23% ↓PPRL (lbs) 22,302 19,483 -2,819 -13% ↓

Last update April 2018: frac hit in May 2018

BAKKEN FULL STRING

Well Details

ToughMet Couplings 381 (replaced SM)Pump Size 1.75”Pump Set Depth 10,160’Tubing L80Rods SteelSPM 4.7Designed Stroke Length 168”Side Loads 50 avg./180 max. lbsDog Leg Severity 0.35 avg/1.8 max ₒ/100 ft Guides/Rod Rotators Yes/No

► Design change:

pump downsized

from 2” to 1.75”

Shale Play BakkenType Full StringInstall Date July 2018Run Time 5 months

BAKKEN FULL STRINGBefore ToughMet After ToughMet Change % Change

Oil (bpd) 48 55 7 15% ↑Gas (mscfpd) 76 141 65 85% -Water (bpd) 66 90 24 36% -Gross Pump Stroke (in) 125 136 11 8% ↑Fluid Level AP (ft) 1390 1398* 8 1% ↑Pump Fillage 85% 92% 7% 8% ↑Gear Box Loading 75.7% 68.3% -7.4% -10% ↓PPRL (lbs) 34000 32684 -1317 -4% ↓PPRL-MPRL (lbs) 18000 16827 -1173 -7% ↓Run Time Per Day 16.0 21.3 5.3 33% ↑System Efficiency 42% 50% 8% 18% ↑

Last update Nov 30, 2018*Fluid level only recorded once

BAKKEN FULL STRING

▶ Fluid production up after ToughMet install

ToughMetinstall

BAKKEN FULL STRING

▶ Spray metal pump card overlay (startup and pump off)

BAKKEN FULL STRING

▶ ToughMet pump card overlay (startup & pump off)

Downhole Stroke Increased 10+ inches

PERMIAN LARGE PARTIAL

Shale Play PermianType PartialInstall Date August 2017Current Run 8.5 months

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Well DetailsToughMet Couplings 126 (replaced SM)Pump Size 2”Pump Set Depth 8880 ft. (set in curve)Tubing L80Rods Fiberglass/SteelSPM 7.5 (VSD)Designed Stroke Length 109”Side Loads 515 lbsDog Leg Severity 3.48Guides Yes

► No major design changes made to this well besides couplings

PERMIAN LARGE PARTIAL

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Before: 6-12 Months1-2 FPY

After:8.5 Months1.41 FPY

Not Yet Failed8.5+ Months <1.41 FPY

ToughMet InstallInstall Failure Rod Failure

Install

PERMIAN LARGE PARTIAL

▶ Data gathered through 4/26/2018; Frac hit 5/29/18

Spray Metal ToughMet Change % Change

Oil (bpd) 111 145 34 31% ↑Gas (mscfpd) 220 235 15.5 7% -Water (bpd) 104 237 133 128% -Downhole Stroke (in) 126.4 175.2 48.8 39% ↑Fluid Level AP(ft) 1629 1550 -79 -5% ↓Pump Fillage 99% 98% -1% -1% ↓Gear Box Load 75% 63% -12% -16% ↓PPRL (lbs) 31893 23322 -8570 -27% ↓

PERMIAN LARGE PARTIAL

▶ Pump card 1/23/2018

SOLUTION 2 TRIAL RESULTS TO DATE

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% of Wells

Improved Did Not Improve

Oil Production 72% 28%System Efficiency 78% 22%Downhole Stroke 86% 14%Pump Fillage 73% 27%PPRL 91% 9%Load Range- Pol Rod 91% 9%Gearbox Loading 95% 5%Fluid Level AP 84% 16%

▶Coupling material has significant effect on operating efficiency

SOLUTION 2 TRIAL RESULTS TO DATE

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Average Change after ToughMet Install

Oil Production 11.7% ↑System Efficiency 20.6% ↑Downhole Stroke 16.0% ↑Pump Fillage 6.4% ↑PPRL -13.1% ↓Load Range- Pol Rod -12.1% ↓Gearbox Loading -12.5% ↓Fluid Level AP -23.8% ↓

▶Data from 15 wells▶Various operators

CHANGES TO GEAR BOX LOADING

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• 95% of wells experienced reduced gearbox loading

• Avg reduction: 12.5%

CHANGES TO LOAD ON POLISHED ROD (RANGE BETWEEN PPRL AND MPRL)

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POLI

SHED

RO

D L

OAD

TIME

EFFECT OF FRICTION ON ALTERNATING POLISHED

ROD LOADS

More Friction Less Friction

Range

• 91% of wells: smaller range between peak and min load

• Avg reduction: 12.1%

SOLUTION 2- WHAT IS IT WORTH?

Financial Value of Solution 2Oil Output Increase 11.7% avgValue at $50/bbl ($/yr)1 $213,525Cost of 150 ToughMet Couplings (Marginal) $(15,000)

Extra Cash Flow ($/yr) $198,525***PLUS the benefit of Solution 1Workover Cost Avoided ($/yr) $75,000

Extra Cash Flow Per Well ($/yr) $273,525

1 Calculated for a well producing 100 bpd

CONTACT

© Materion Corporation 201837

IN SUMMARY▶The ToughMet alloy mitigates

wear on production tubing—Improve run time up to 8Xs—Reduce work over costs

▶ToughMet is low friction vs. steels—Minimizes drag on rod string—Smoother rod string movement —Optimizes efficiency, reduces

loads, and improves fluid productivity of well

Richard Cash

M: 936.581.1912E: richard.cash@materion.com

Performance Alloys & Composites Field Sales