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.

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Introduction

  A coating process developed for steel downhole components with a proprietary Al 2 O 3 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 H 2 S and CO 2 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 Al 2 O 3 material.

base proprietary ceramic-type 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 H 2 S and / or CO 2  Well depth varied between 4300 to 6800 feet.

H

2

S 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 lower strength steels if high partial pressures develops.

Hydrogen Damage

Hydrogen Embrittlement Cracking

CO

2

Corrosion

  CO 2  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  CO 2 mole % = 4%   CO CO 2 2 mole fraction = 0.04

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 H 2 S.

Coated with Aliron [ceramic like] material of about 5 mills.

Duration to 720 hrs maximum.

Battelle Test Results- Coated Samples

Coated [ksi] AISI 4130 [88ksi] Specimen N1 N2 N4 N5 N3* AISI 4130 [104ksi] N6 U1 U2 U4 U5 U3 U6 Load, (% Yield) 42.5 53.2

71.2

79.2

62/81.9 (93) Hours 720 720 720 720 720 Defective Sample [large inclusion] 51.4

______ 720 65.1

78 94 98.2

102.9 (99) 720 720 720 720 720 Fail--No Fail NF NF NF NF NF ___ NF NF NF NF NF NF Remarks 424/720 =1,144 hrs No Test

NMTU Tests- Coated and Uncoated Samples

4140

1 2 2.1

3 3.1

4 5

1045

1 2 2.1

3 3.1

4 5

Condition

As Received Normalized C + N Q + T C + Q + T Q + T Q + T As Received Normalized C + N Q + T C + Q + T Q + T Q + T

Austen F

Cold Drawn 1600 1600 1560 oil 1560 oil 1560 oil 1560 oil

Temper F

none Air cool 1325 1000 1325 1150 1300 Cold Drawn 1600 1600 1550 water 1550 w 1550 w 1550 w none air 1325 1000 1325 1150 1300

Yield ksi

120 100 72 124 99 100 81 90 80 52 145 115 95 80

Tensile ksi

144 140 99 131 112 109 90

HRC

33 32 27 32 29 29 20 110 91 76 155 120 115 90 22 18 15 34 31 26 19

NMTU SCC Test Results

Sample No. 2.8 Nor 2 .6 Nor 2.4 Nor 2.1 C + Nor 3(9) Q+T 3(7) Q+T 3(4) Q+T 3.1 C + Q+T 4(8) Q+T 4(5) Q+T 4(2) Q+T 5(6) Q+T 5(3) Q+T 5(1) Q+T Stress % [Y ksi] 80 [100] 4140 Load, k# 80 60 40 60 40 115 [72] 83 80 [124] 99 60 40 98 [99] 80 74.4

49.6

97 80 60 40 80 60 40 60 40 64.4

48.3

32.2

Fail, Hrs 5 11 20 60[def] 4.5

6 9 720NF 9.5

22 185 12 63 400NC Stress % [Y ksi] 80 [80] 60 40 104 [52] 80 [145] 60(8) 40(5) 97 [115] 80(7) 60(4) 40(2) 80(6) 60(3) 40(1) 1045 Load, k# 64 48 32 54 116 87 58 112 76 57 38 64 48 32 Fail, Hrs 9 18 31 720NF 7 14 62 720NF 22 45 75 70 100NC 200NC

NMTU SCC Test Results

800 700 600 500 400 300 200 100 0 0

NMTU 4140 Coated vs uncoated Coated NF, 97%/99 ksi y

20 40 60

Load, ksi

80 100 120

NMTU SCC Test Results

NMTU 1045 Coated vs uncoated

800 700 600 500 400 300 200 100 0 0

Coated NF, 97%/112 ksi y

50

Load, ksi

100 150

Test Locations

 The Snyder, Texas areas were selected for high CO 2 fluids used for tertiary recovery.

 The Penwell in West Texas selected for naturally high H 2 S fluids.

Field Tests Results

   Four coated pony rods were tested in a Penwell, Tx well with fluids containing heavy amounts of H 2 S and CO 2 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.