Chapter 1 - Introduction

01-01 - Corrosion Problem Definition For Hydrofracked Wells (17 min.) Sample Lesson
01-02 - Mandatory On-Site Testing (16 min.) Quiz: 01-02 - Mandatory On-Site Testing

Chapter 2 - Potential Pitting Corrosion and Cracking Mechanisms/Failure Modes

02-01 - Internal Corrosion, CO₂ Corrosion (17 min.)
02-02 - Sour Corrosion, Oxygen Corrosion, MIC (22 min.)
02-03 - MIC (Continued) (6 min.)
02-04 - SSC, Erosion Corrosion, External Corrosion and Stray Current Interference (27 min.) Quiz: 02-04 - SSC, Erosion Corrosion, External Corrosion and Stray Current Interference

Chapter 3 - Operational Challenges

03-01 - Flowback of Fluids (11 min.)
03-02 - Produced Water Handling & Disposal (25 min.)
03-03 - Hydrates, Paraffins & Asphaltenes (19 min.) Quiz: 03-03 - Hydrates, Paraffins & Asphaltenes

Chapter 4 - Corrosion Monitoring

04-01 - Direct Monitoring Techniques (16 min.)
04-02 - Probes & Sensors (29 min.)
04-03 - Indirect Monitoring Techniques (7 min.)
04-04 - Sample Selection, Collection and Preservation (26 min.) Quiz: 04-04 - Sample Selection, Collection and Preservation

Chapter 5 - Corrosion Mitigation Strategies

05-01 - Corrosion Mitigation Strategies (12 min.)
05-02 - Materials Selection (27 min.)
05-03 - Chemical Treatment Protocols (22 min.)
05-04 - Process & Field Operational Changes (22 min.) Quiz: 05-04 - Process & Field Operational Changes

Chapter 6 - Case Studies

06-01 - Previous Client-Approved Investigations (31 min.)
06-02 - Lessons Learned (17 min.)

Chapter 7 - Canadian and US Pipeline Regulations and Standard Practices

07-01 - Industry Guidelines, Compliance & Reporting (14 min.) Quiz: 07-01 - Industry Guidelines, Compliance & Reporting

Chapter 8 - Conclusions

08-01 - Recap of Key Points (27 min.)

Hydrofracking of Shales and Associated Internal Corrosion Problems / Chapter 1 - Introduction

Lesson 01-01 - Corrosion Problem Definition For Hydrofracked Wells

Access All SAGA Wisdom Training content Subscribe

Already a member? Sign in

Access All SAGA Wisdom Training content Subscribe

Already a member? Sign in

Transcript

01. Lesson 1.01: Corrosion Problem Definition For Hydrofracked Wells 02. Introduction to Hydraulic Fracturing 03. Internal Corrosion in Hydrofracked Wells 04. Internal Corrosion in Hydrofracked Wells (2)05. Internal Corrosion in Hydrofracked Wells (2)06. OCTG Damage from Oxygenated Shale Oil Production 07. OCTG Damage from Oxygenated Shale Oil Production (2)08. OCTG Damage from Oxygenated Shale Oil Production (3)09. Solids Testing 10. Procedure for Measuring pH of Solid Samples 11. Procedure to Determine Sulfides or Carbonates 12. Procedure to Determine Sulfides or Carbonates (2)13. Procedure to Determine Sulfides or Carbonates (3)14. Lab Testing - Solids

01. Lesson 1.01: Corrosion Problem Definition For Hydrofracked Wells

Good day everybody. My name is Patrick Teevens. I am the president and owner of Broadsword Corrosion Engineering Ltd. in Calgary, Alberta, Canada.
I am doing a course on "Hydrofracking of Shales and Associated Internal Corrosion Problems". This course is intended to give a better insight into the consequences of hydrofracking and the often missed corrosion problems that are associated with it, and particularly with hydrocarbon producing shale formations. And we will address both of those throughout the course. I think you will find this of interest. We're going to talk about the course on a global basis on what's happening. And we're going to drill down into corrosion mechanisms, mitigation programs, how you can control your corrosion through metallurgy, what to look out for, and a variety of different ways of handling this often overlooked and sometimes ignored problem.

02. Introduction to Hydraulic Fracturing

So about 67% of the gas production and 43% of crude oil production has been hydrofracked in the United States. And that's over 2 million wells since 1949. There's been several environmental and safety concerns raised, primarily since the 1980s when this really turned on to be a big, major issue with oil and gas producers, is that roughly 95% of all wells that are being drilled and produced now are being fracked through hydrofracking. And so since the 1980s there's been 8 concerns raised by the Department of Energy, and these are: Water and groundwater contamination; Air pollution and volatile organic compounds releases; Induced seismic activity in terms of earthquakes or some minor ground movement associated with these hydrofracs; Disturbance of land and wildlife; Chemical spills and wastewater disposal challenges; The depletion of freshwater resources in arid regions; And there's health risks related to air and water contamination. So these are legitimate concerns. They might be overstated in some cases, but at least they're there and you should be cognizant of what the key issues are from all perspectives.
What we're trying to do here in this course is to look at the internal corrosion integrity of downhole OCTGs and your line pipe. And internal corrosion is in itself a critical yet overlooked threat to overall wellbore and pipeline integrity.

03. Internal Corrosion in Hydrofracked Wells

So in hydrofracked wells, internal corrosion inOCTGs and pipelines is often ignored. Failures happen rapidly, in less than 10 years, and that's considered to be abnormal. In most North American applications, if you have pipelines failing in less than 10 years, that's considered really by practice to be an abnormal condition. Pipelines are at least intended or originally intended to last 25 years and in many cases now, officially or unofficially (depending on who you talk to), these pipelines are intended to last 75 years now. So really anything under 10 years is abnormal. Another concern is the water carryover from fracking introduces corrosion risks. And that's where I come in. It is a big one. It's your flowback water. It's your hydrofracked water that you're using to frack, and then the flowback water that comes back in a period of time and what is that doing in terms of downhole and surface corrosion. And to add to the mix, in May of 2023 PHMSA (the Pipeline Hazardous Materials Safety Administration) came out with their MEGA rules in their final ruling on RIN 2, and that was the extended reporting and safety requirements to about 400,000 miles of gathering pipelines that were formerly not subject to any federal safety oversight. So that's really increased the bailiwick of lines that are now involved in the PHMSA regulations under the medium consequence (or MCA) rule.
I did investigations personally. You can see the photographs on the side here of these 2 sample bottles. And these are waters that were collected from a maintenance de-watering pig in Louisiana. And the yellow hue of the turbid or cloudy water samples suggest the possibility of ferric cations and/or sulfur-bearing species in that water. And that's exactly what we did find. But we also found that the Haynesville shales in Louisiana just east of Shreveport showed about a 5 - 20x increase in corrosion rates. And these are factors contributing to severe corrosion, including free water with high CO₂ and elevated H₂S levels, dissolved oxygen contaminated accelerated sweet corrosion (sweet corrosion being defined as CO₂ corrosion in the absence of H₂S), and high salinity and microbiologically-influenced corrosion. So we initially did this work in 2009, 2010, and there's been alot of definition come to this in the last few years. But item 5b there, dissolved oxygen, is the major culprit. And then that dissolved oxygen then sets off a cascading series of events leading to both sweet, sour, and ultimately MIC (or Microbiologically-Influenced Corrosion).

04. Internal Corrosion in Hydrofracked Wells (2)

So 7 of the 8 risks associated with hydrofracking are the trickle-down risks from unmitigated or undetected corrosion, which is usually due to the absence of a robust corrosion management plan.PHMSA regulation CFR 49 Part 192 for gas pipeline systems requires prompt actions to mitigate any potential damage to pipelines, in which 'prompt' is newly defined in the regulation. Operators must also bolster their corrosion programs in high-consequence areas through additional measures, including testing and record-keeping provisions. Now every pipeline or downhole tubular failure which I have investigated over a 46-year career have had a common thread. No CMS or corrosion management system and no operator comprehension of the threat. Two cases where I worked on personally was the El Paso Oil and Gas, Carlsbad, New Mexico failure of August 2000 and the subsequent 2009 litigation, and the Gail Gas Authority of India Ltd., Tatipaka, India June 2014 failure and the December 2014 investigation. In both of those cases air contaminated water (saturated), and gas transmission pipelines were loaded with oxygen. And in the case of the pipelines themselves, they had unexpected or unanticipated water in them. Both of these investigations resulted in fatalities. 12 in the El Paso case and a minimum of 22 people in the Tatipaka case.

05. Internal Corrosion in Hydrofracked Wells (3)

So air contamination and hence dissolved oxygen in free water are manmade events. There are 100% preventable.Hydraulic fracturing invariably uses fresh surface runoff waters or sources and are saturated with dissolved oxygen as a function of temperature and pressure. So, for example, surface waters have their highest concentrations of oxygen at about 4°C, and as it warms up in the summertime the oxygen evolves off like water boiling on a stove, and your lowest concentrations of oxygen in surface water are during the hot summer periods. So depending upon source and temperature you're frac water... it's pretty much loaded up with anywhere from 4 - 12 ppm of dissolved oxygen in it, and then you're putting that into a wellbore. So when oxygen is introduced into a natural gas system containing free water, there's a significant increase in both general and localized pitting. You can see this picture on the right, that this is a dissolved oxygen accelerated attack in internal tubing on a hydrofracked sour multiphase well with microbiologically-influenced corrosion in northern Alberta, Canada. Dissolved oxygen will significantly accelerate pitting corrosion, especially when mixed with CO₂ and H₂S. It'll increase by at least 1 - 2 orders of magnitude higher than an oxygen free environment. So that folks is very, very important.

06. OCTG Damage from Oxygenated Shale Oil Production

Now, I've got pictures here of another oxygenated shale oil production from northern Alberta from 2015. And you can see this is one that had failed. The picture on the right is the OD of that tubing string. Of course, the picture on the left is the tubing string cut in half. And you can see where this preferential pitting had occurred.

07. OCTG Damage from Oxygenated Shale Oil Production (2)

Internal corrosion damage here. On the left is before being cleaned up. There's lots of corrosion product around it, lots of activity, and pretty aggressive corrosion rates. And then on the right, this is after sandblasting of the sample, and you can see the extent of the damage in there. Sometimes, to the untrained eye, it may look like it's a mound. But those are pits. Those are deep cavernous pits leading to holes in the line.

08. OCTG Damage from Oxygenated Shale Oil Production (3)

More OCTG damage from an oxygenated shale oil production. There is an erosion/corrosion pattern here, and again, corrosion seepage into the threaded areas of these couplings. And again, massive attack and definitely accelerated by oxygen.

09. Solids Testing

So when a pipeline is pigged, solid materials may be removed from the pipe wall and may mix with liquids, forming sludge. That's almost a guarantee. Some adherent deposits are expected to remain on the pipe wall even after aggressive cleaning. It's almost impossible to get a pristine clean. You can get them pretty darn clean, and you may have to get aggressive with chemicals if you're really wanting it super clean, for maybe an ILI run that's requiring that. But you're going to get solids, that's inevitable.Samples of these materials should be collected and one or more of the following tests typically performed on site: pH is a given. As soon as you can get a sample you get the pH, because the pH in-situ is always going to be lower than pH you get on a sample because the gases are flashing off from the liquid itself; You want to measure sulfides, carbonates, and bacteria (or RK or microbes).Carbonate compounds may be present inside a pipe due to reaction with steel to form iron carbonate or citerite or a water-borne scale on the pipe surface. And the presence of sulfide may indicate of H₂S or hydrogen sulfide has reacted with a steel pipe to form iron sulfide.

10. Procedure for Measuring pH of Solid Samples

So the procedure for measuring the pH of a solid sample is pretty straightforward. Use a spatula in a small sample in the clean weighing boat. You observe the color, odor, and texture of the sample. If the sample is a piece of scale, grind it into small pieces. If possible use a spatula to break up the solid pieces. You moisten a strip of pH paper with 2 drops of distilled water from the wash bottle, and you record the pH. Then you moisten the sample solid with 2 - 3 drops of distilled water and place the pH paper on the moistened solids and record any color change. And simply record your pH.

11. Procedure to Determine Sulfides or Carbonates

The procedure to determine the presence of sulfide or carbonate is relatively easy. And this is amazing. You can go out to the field and you don't need alot of expensive test equipment. It's relatively inexpensive, and you get a mountain's worth of data right from doing these on-site tests. In this particular example, they're taking a small sample of sludge here, they're putting it in a test tube. They have a piece of paper here that's sensitive to H₂S, usually copper acetate (used to be lead acetate), and you're going to put some acid in there, hydrochloric acid. So you wet this piece of led acetate paper with distilled water, you draw 1 mL of fluid from 1normal or 1 molar HCl into a pipette, and they dispense the acid into a test tube all at once and note if the bubbles are produced when the acid is added. If it effervesces that means you've got CO₂ in there. And immediately place that wetted test paper in the mouth of the test tube with the small tail hanging over the outside of the test tube.

12. Procedure to Determine Sulfides or Carbonates (2)

And loosely place a rubber stopper on it. Loosely, because it's going to build up gas. You gently agitate the sample for about 30s and you observe the color of the test paper. If this lead or copper acetate paper turns brown or black, that usually indicates the presence of sulfides are forming, lead sulfide or copper sulfide. And because of the issues with lead, more often than not it's going to be copper. The presence of sulfide is also indicated by the rotten egg smell.

13. Procedure to Determine Sulfides or Carbonates (3)

So if it turns brown or silvery brown, it's a test positive for sulfides with the lead acetate paper. It's a little more black when it comes to copper sulfides. If no color change is noted, the test is negative for sulfides. If bubbling occurs when HCl is added to the sample, the test is also positive for carbonates. If no bubbles are produced and the lead acetate paper fails to turn brown, the test is negative for sulfide and carbonates.

14. Lab Testing - Solids

So those are some of the easy tests that we can do on site. We haven't told you about dissolved oxygen yet. That'll come up in a little while. But we get these liquid samples to a petrographic lab where they can do more sophisticated work like X-ray diffraction andenergy dispersive spectroscopy. So what you're seeing here is a sample XRD analysis from work that we had done with a client. And you can see it's very, very effective in finding out what crystals or materials they have in the sample and their relative abundances in terms of weight percent. So in this particular sample, you can see the majority of it is sand or quartz at 44%, and then we have iron oxyhydroxide (or Goethite) at 9.5%, then we've got magnetite here (Fe₃O₄) at 2.9%. We even got some paraffins or waxes here at 9%. It gives you the breakdown.
So this is essential in understanding what's going on in your pipeline after fracking or any time in any sort of service pipeline.
Hosein, Sasan M. "PHMSA Gas Pipeline Mega Rule." In AMPP CORROSION, pp. AMPP-2024. AMPP, 2024.Cuervo, Bernardo. "The 2021 US Gas Gathering Final Rule and the New Challenges to Pipeline Integrity." In AMPP CORROSION, pp. AMPP-2024. AMPP, 2024.