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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

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evaluation of the aliron corrosion resistant coating in downhole application

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


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.

  • 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.


  • 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.
h 2 s corrosion
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 lower-strength steels if high partial pressures develops.
hydrogen damage
Hydrogen Damage

HydrogenEmbrittlement Cracking

co 2 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
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
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
NACE TM 01-77

Fig. 1 Test Apparatus

laboratory conditions
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.
nmtu scc test results1
NMTU SCC Test Results

Coated NF, 97%/99 ksi y

nmtu scc test results2
NMTU SCC Test Results

Coated NF, 97%/112 ksi y

test locations
Test Locations
    • The Snyder, Texas areas were selected for high CO2 fluids used for tertiary recovery.
  • The Penwellin West Texas selected for naturally high H2S fluids.
field tests results
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
Downhole Corrosion Results

This shows heavy spalling of the case hardened sucker rod caused by hydrogen embrittlement.

downhole corrosion results1
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 results2
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.



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.