enhance performance & extend run life of rod …
TRANSCRIPT
ENHANCE PERFORMANCE & EXTENDRUN LIFE OF ROD PUMPED WELLS
WITH SPECIALTY COUPLING ALLOY
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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: 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
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!"#$%& '"% !$() = !"#$%& +,$-".) /,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: 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
▶ 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% ↓
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: [email protected]
Performance Alloys & Composites Field Sales