Corrosion Resistant Coating Test Program

Report
Evaluation of the Aliron
Corrosion Resistant Coating in
Downhole Application
May 15, 2013
Aliron Tool Research,
Tony Rallis, Owner, President
PO Box 287
Coppell, TX 75019
www.alirontool.com
This document contains privileged and confidential information which is subject to the works product
doctrine and is intended only for the internal use of Aliron Tool Research or other contributing parties
and any unauthorized use, dissemination or replication of this document or information contained
within is strictly prohibited.
Introduction


A coating process developed for steel downhole components with a proprietary
Al2O3 based metalloid coating appears to provide an excellent barrier to general,
pitting, hydrogen embrittlement, sulfide stress cracking and other forms of
corrosion attack.
 Laboratory Tests: NACE TM-01-77 tests results of hardened steel
specimens, stressed to 112 ksi [97% yield] resulted in no“720 hour failures,
whereas uncoated samples only lasted three to a few hours under the same test
conditions.
 Field Tests: Coated high strength pony rods and steel fiberglass rod pins were
installed in West Texas wells with aggressive H2S and CO2 environments and
pulled after one to three years in service with no appreciable corrosion
damage. Uncoated parts were heavily damaged or embrittled.
This presentation will review the results of the laboratory test results of Aliron
coated and uncoated test samples and an analysis of the field test results comparing
coated vs. uncoated components from the same wells.
Introduction
 Original laboratory and field program funded by DOE and
Space Alliance Technology Outreach Program of Houston.
 Coating is modified Al2O3 base proprietary ceramic-type
material.
 Several test steel samples and downhole tools.
 NACE TM 01-77 at Battelle laboratory and NMTU.
 Field tests consisted of Schlumberger IPM wells in West
Texas with high concentrations of H2S and / or CO2
 Well depth varied between 4300 to 6800 feet.
H2S Corrosion
 Corrosion Damage in the Oil Field
 Frequently in downhole equipment
and piping causing HIC, SCC, SSC.
 Occurs in higher strength steels
> than 25 HRC. NACE MR 01-75
 Sudden, unexpected failures occur • Absorption of hydrogen causes
• Loss of ductility in steel
 Fracture surfaces display brittle or granular appearance
 Hydrogen-induced cracking and blistering can occur in lowerstrength steels if high partial pressures develops.
Hydrogen Damage
Hydrogen Embrittlement Cracking
CO2 Corrosion
 CO2 Corrosion
 PP < 3 psig, corrosion not likely
 3 psig < PP < 30 psig, light to moderate corrosion
 PP > 30 psig, produces a severely corrosive
environment
 Example in Tubing or Pipe






Operating pressure = 1,000 psig
CO2 mole % = 4%
CO2 mole fraction = 0.04
CO2 partial pressure = 0.04 x 1000 psig
= 40 psig
Results in severe corrosion
Mitigation of Corrosion
 General and Pitting Corrosion
 Resistant material
 Chemical inhibition; batch and continuous
 Change environment- electrolyte, temperature
 Effective Coating
 Embrittlement, SCC, SSC, etc.
 Change environment
 Lower stress
 Lower hardness
 Resistant Material
 Effective Coating
NACE TM 01-77 SSC Tests
 Battelle Labs and NMTU Metallurgy Department
 Determine material susceptibility.
 Susceptible materials – listed in NACE MR 01-75.
 Simulated downhole environment – (pH 3.5).
 Temperature – corrosion reaction velocity.
 Applied stress – tension to 104% of yield strength.
 Time – duration of test to 720 hours.
 Test Sample – sub-sized tensile bar in autoclave.
 Usually a test for alloy resistance to SSC.
NACE TM 01-77
Fig. 1 Test Apparatus
Laboratory Conditions
 Battelle samples- AISI 4130 steel alloy in two
yield strength levels, 88,000 and 104,000 psi.
 NMSU samples- AISI 4140 (112 ksi) and 1045
(120ksi).
 Simulated downhole environment with a pH of
3.5 including bubbling H2 S.
 Coated with Aliron [ceramic like] material of
about 5 mills.
 Duration to 720 hrs maximum.
Battelle Test Results- Coated Samples
Coated [ksi]
Specimen
Load, (% Yield)
Hours
Fail--No
Fail
AISI 4130 [88ksi]
N1
42.5
720
NF
N2
53.2
720
NF
N4
71.2
720
NF
N5
79.2
720
NF
N3*
62/81.9 (93)
720
NF
424/720
=1,144 hrs
N6
Defective Sample
[large inclusion]
______
___
No Test
U1
51.4
720
NF
U2
65.1
720
NF
U4
78
720
NF
U5
94
720
NF
U3
98.2
720
NF
U6
102.9 (99)
720
NF
AISI 4130
[104ksi]
Remarks
NMTU Tests- Coated and Uncoated Samples
4140
Condition
Austen F
Temper F
Yield ksi
Tensile ksi
HRC
1
As Received
Cold Drawn
none
120
144
33
2
Normalized
1600
Air cool
100
140
32
2.1
C+N
1600
1325
72
99
27
3
Q+T
1560 oil
1000
124
131
32
3.1
C+Q+T
1560 oil
1325
99
112
29
4
Q+T
1560 oil
1150
100
109
29
5
Q+T
1560 oil
1300
81
90
20
1
As Received
Cold Drawn
none
90
110
22
2
Normalized
1600
air
80
91
18
2.1
C+N
1600
1325
52
76
15
3
Q+T
1550 water
1000
145
155
34
3.1
C+Q+T
1550 w
1325
115
120
31
4
Q+T
1550 w
1150
95
115
26
5
Q+T
1550 w
1300
80
90
19
1045
NMTU SCC Test Results
Sample No.
Stress % [Y ksi]
4140
Load, k#
Fail, Hrs
Stress % [Y ksi]
1045
Load, k#
Fail, Hrs
2.8 Nor
80 [100]
80
5
80 [80]
64
9
2 .6 Nor
60
60
11
60
48
18
2.4 Nor
40
40
20
40
32
31
2.1 C + Nor
115 [72]
83
60[def]
104 [52]
54
720NF
3(9) Q+T
80 [124]
99
4.5
80 [145]
116
7
3(7) Q+T
60
74.4
6
60(8)
87
14
3(4) Q+T
40
49.6
9
40(5)
58
62
3.1 C + Q+T
98 [99]
97
720NF
97 [115]
112
720NF
4(8) Q+T
80
80
9.5
80(7)
76
22
4(5) Q+T
60
60
22
60(4)
57
45
4(2) Q+T
40
40
185
40(2)
38
75
5(6) Q+T
80
64.4
12
80(6)
64
70
5(3) Q+T
60
48.3
63
60(3)
48
100NC
5(1) Q+T
40
32.2
400NC
40(1)
32
200NC
NMTU SCC Test Results
NMTU 4140 Coated vs uncoated
800
700
Coated NF, 97%/99 ksi y
Hours
600
500
400
300
200
100
0
0
20
40
60
Load, ksi
80
100
120
NMTU SCC Test Results
NMTU 1045 Coated vs uncoated
800
700
Coated NF, 97%/112 ksi y
Hours
600
500
400
300
200
100
0
0
50
100
Load, ksi
150
Test Locations
 The Snyder, Texas areas were selected for high CO2
fluids used for tertiary recovery.
 The Penwell in West Texas selected for naturally high
H2S fluids.
Field Tests Results
 Four coated pony rods were tested in a Penwell, Tx well with fluids
containing heavy amounts of H2S and CO2 were installed on June
15, 2003 and pulled from the well on June 15, 2004. Although scale
was formed on the surface no corrosion damage occurred. [see
photos]
 Also installed was an uncoated sucker rod that was induction
hardened on the outer surface to about 50 HRC. Visual inspection of
the surface shows very heavy corrosion damage caused by hydrogen
embittlement of the outer case and subsequently causing spalling
failure. [see photos]
 Fiberglass sucker rod string with coated steel pin ends that were
operated for three years showed some scale build up did not show
any corrosion damage. Samples are available for inspection.
Downhole Corrosion Results
This shows heavy spalling of the case hardened sucker rod caused by hydrogen embrittlement.
Downhole Corrosion Results
Coated pony bar at left
tested in high H2S crude
shows no corrosion
damage after one year
Uncoated pony bar at right
tested in the same well
shows heavy corrosion
damage after one year.
Downhole Corrosion Results
This pony rod was cut in half to show the
coating condition after testing in the well
for six months. The top section was clean
to show that the coating was still intact and
the section at the bottom shows the rod as
it came out of the well.
Summary
Aliron Tool Research developed this coating for the purpose of offering well operators a
solution to corrosive downhole problems with a performance level at or above the
prevailing plastic coatings and fiberglass liners. With this coating well operators can
achieve the same or better corrosion resistance at a significant cost reduction.
The laboratory and field test program, as well as the three year results of the coated steel
pin-ends of a fiberglass sucker rod string in the Waddell et. al. Amaine 69, have yielded
great success. Now Aliron Tool would like to leverage this success by coating the inside
surface of oil country tubular products and other viable components on a larger scale. At
this point the test results indicate this coating will successfully provide excellent
corrosion protection in very aggressive fluids, resist very tough handling and high
temperatures at a significant cost savings. With this goal in mind, Aliron Tool Research
is seeking the input and assistance of the Artificial Lift community to develop 100 blast
joint prototypes for field use and eventual commercialization.

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