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, PresidentPO Box 287Coppell, TX 75019www.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.

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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 lower-

strength 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 RemarksAISI 4130 [88ksi] N1 42.5 720 NF

N2 53.2 720 NFN4 71.2 720 NFN5 79.2 720 NF

N3* 62/81.9 (93) 720 NF 424/720 =1,144 hrs

N6 Defective Sample [large inclusion]

______ ___ No Test

AISI 4130 [104ksi]

U1 51.4 720 NF

U2 65.1 720 NFU4 78 720 NFU5 94 720 NFU3 98.2 720 NF

U6 102.9 (99) 720 NF

NMTU Tests- Coated and Uncoated Samples

4140 Condition Austen F Temper F Yield ksi Tensile ksi HRC

1 As Received Cold Drawn none 120 144 332 Normalized 1600 Air cool 100 140 32

2.1 C + N 1600 1325 72 99 273 Q + T 1560 oil 1000 124 131 32

3.1 C + Q + T 1560 oil 1325 99 112 294 Q + T 1560 oil 1150 100 109 295 Q + T 1560 oil 1300 81 90 20

1045  1 As Received Cold Drawn none 90 110 222 Normalized 1600 air 80 91 18

2.1 C + N 1600 1325 52 76 153 Q + T 1550 water 1000 145 155 34

3.1 C + Q + T 1550 w 1325 115 120 314 Q + T 1550 w 1150 95 115 265 Q + T 1550 w 1300 80 90 19

NMTU SCC Test Results

 Sample No. Stress % [Y ksi]4140

Load, k#  Fail, Hrs Stress % [Y ksi]1045

Load, k#  Fail, Hrs2.8 Nor 80 [100] 80 5 80 [80] 64 9

2 .6 Nor 60 60 11 60 48 182.4 Nor 40 40 20 40 32 31

2.1 C + Nor115 [72]

83 60[def] 104 [52] 54 720NF3(9) Q+T 80 [124] 99 4.5 80 [145] 116 73(7) Q+T 60 74.4 6 60(8) 87 143(4) Q+T 40 49.6 9 40(5) 58 62

3.1 C + Q+T 98 [99] 97 720NF 97 [115] 112 720NF4(8) Q+T 80 80 9.5 80(7) 76 224(5) Q+T 60 60 22 60(4) 57 454(2) Q+T 40 40 185 40(2) 38 755(6) Q+T 80 64.4 12 80(6) 64 705(3) Q+T 60 48.3 63 60(3) 48 100NC5(1) Q+T 40 32.2 400NC 40(1) 32 200NC

NMTU SCC Test Results

0100200300400500600700800

0 20 40 60 80 100 120

Hou

rs

Load, ksi

NMTU 4140 Coated vs uncoated

Coated NF, 97%/99 ksi y

NMTU SCC Test Results

0

100

200

300

400

500

600

700

800

0 50 100 150

Hou

rs

Load, ksi

NMTU 1045 Coated vs uncoated

Coated NF, 97%/112 ksi y

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.