**Nader Vahdati 1,\*, Xueting Wang 1, Oleg Shiryayev 2, Paul Rostron <sup>1</sup> and Fook Fah Yap <sup>3</sup>**


Received: 12 December 2019; Accepted: 21 January 2020; Published: 26 January 2020

**Abstract:** Oil flowlines, the first "pipeline" system connected to the wellhead, are pipelines that are 5 to 30.5 cm (two to twelve inches) in diameter, most susceptible to corrosion, and very difficult to inspect. Herein, an external corrosion detection sensor for oil and gas pipelines, consisting of a semicircular plastic strip, a flat dog-bone-shaped sacrificial metal plate made out of the same pipeline material, and an optical fiber with Fiber Bragg Grating (FBG) sensors, is described. In the actual application, multiple FBG optical fibers are attached to an oil and gas pipeline using straps or strips or very large hose clamps, and, every few meters, our proposed corrosion detection sensor will be glued to the FBG sensors. When the plastic parts are attached to the sacrificial metals, the plastic parts will be deformed and stressed; thus, placing the FBG sensors in tension. When corrosion is severe at any given pipeline location, the sacrificial metal at that location will corrode till failure and the tension strain is relieved at that FBG Sensor location, and therefore, a signal is detected at the interrogator. Herein, the external corrosion detection sensor and its design equations are described, and experimental results, verifying our theory, are presented.

**Keywords:** corrosion sensor; oil and gas pipelines; optical fibers; Fiber Bragg Grating (FBG)

#### **1. Introduction**

Pipelines are the most practical, economical, and safest way of transporting crude or refined oil and gas (O&G) around the world. A study done by the Fraser Institute [1], comparing safety of transporting oil and gas (O&G) by rail versus pipelines, revealed that both ways are safe but pipelines are the safest transportation mode. Even all living creatures except flatworms, nematodes, and cnidarians have circulatory systems and use veins and arteries (pipelines) to transport blood, oxygen, and nutrients to their bodies. However, from time to time, rupture of the pipelines or veins and arteries can occur. In the case of O&G pipelines, as they are transporting flammable and very hazardous materials, any rupture or defect of the pipeline can potentially result in explosions, fires, release of toxic gases, loss of human lives, property damage, and environmental disasters. Many living creatures and humans have a nervous system, which can detect rupture of veins and arteries when it occurs (acting as a health monitoring system) to warn humans of occurrence of such events, but such health monitoring systems are nonexistent in most O&G fields.

The purpose of this research is to develop a health monitoring system (a corrosion detection sensor) using fiber optics to facilitate detection of external corrosion and help prevent leaks in exposed O&G pipelines. In this paper, an external corrosion detection sensor for O&G pipelines, consisting of a semicircular plastic strip, a flat dog-bone-shaped sacrificial metal plate made out of the same pipeline material, and an optical fiber with FBG sensors, is described. The external corrosion detection sensor and its design equations are described, and experimental results, verifying our theory, are also presented.

### *1.1. Literature Review—Corrosion Prevention*

Protective coatings (zinc, epoxy, paint, and other polymers) applied to the outside of O&G pipelines, and cathodic protection are two most commonly used methods [2] by the oil industry to control and inhibit external corrosion of buried pipelines. For above the ground pipelines, which is the focus of this paper, cathodic protection is not an option since the electrolyte (water or soil) is not present and protective coating is the only external protection. The most common types of coatings used in the O&G industry are zinc coating, created during manufacturing of the pipelines and epoxy coating, which is a paint-like substance that seals the surface of the pipeline. Pipeline coating prevents the metal pipe from being in direct contact with the environment, thus extending its life.

Despite the use of coatings, due to mechanical and environmental damages to the coating, external corrosion still takes place on above the ground pipelines. As most oil fields lack a corrosion monitoring system, corrosion can occur undetected.

Another indirect method used to protect pipelines from external corrosion has been pipeline insulation, acting like coatings. Pipeline insulation is used to reduce energy loss, maintain temperature in O&G pipelines, control paraffin waxes from precipitation, and prevent pipelines from freezing and cracking, and is designed to be water tight to prevent infiltration of water from the outside environment onto the pipeline surface; thus, protecting the pipelines from external corrosion but due to mechanical and environmental damages to the insulation, water invariably seeps into the insulation, and pipeline corrosion occurs. Corrosion under insulation (CUI) or corrosion under fire-proofing (CUF) is reported by most O&G and petrochemical companies to be one of their worst nightmares. The cost associated with controlling corrosion is astronomical. On 21 June 2016, PHMSA (US Pipeline and Hazardous Materials Safety Administration) issued an advisory bulletin [3] warning the pipeline industry about Corrosion Under Insulation (CUI). Thermal insulation not only has failed to shield O&G pipelines from external corrosion, but has actually exacerbated the corrosion problem.

Corrosion of low carbon steel pipelines cannot be entirely eliminated but can only be controlled; meaning occurrence of corrosion is a certainty. Thus, there is a definite need for corrosion detection, and inspection. As corrosion is a major threat to O&G pipelines, its inhibition and timely detection are the two key parts of pipeline integrity practice.

#### *1.2. Literature Review—Corrosion*/*Leak Detection Sensors*

In the past four years, numerous in-depth review papers have been published [4–11] that show inspection techniques commonly used by the O&G industry for external and internal corrosion detection of O&G pipelines.

For above the ground O&G pipelines without an insulation or with insulations removed, visual inspection, ultrasonic thickness measurement method, Pipeline Inspection Gage (PIG) or Inline Inspection (ILI) tool, and Hydrostatic Pressure Testing (HT) are four main pipeline integrity inspection techniques used by most O&G companies to detect external corrosion and assess if a corroded pipeline is safe to be in operation or not. These techniques have their advantages and disadvantages, and each reflects a different, unique aspect of the overall pipeline integrity management.

The first and the simplest method of inspection is, of course, visual inspection, but it is also the most expensive and time-consuming method. It involves a person walking along the pipeline and checking the surface condition of the pipe, looking for dents, pitting corrosion, metal loss, cracks, and other defects. Visual inspections are usually performed with portable visual scanners (laser scanners), which allow for precise, traceable sizing of surface corrosion at the outer diameter of the pipeline. The task of visual inspection of O&G pipelines becomes harder when insulations are involved. Insulation has to be first removed before the visual inspection and later replaced when visual inspection

is complete. This is why this method is labeled as expensive and time-consuming. Corrosion under insulation (CUI), as explained earlier, is one of the most difficult corrosion processes to detect and prevent, as the insulation covers the corrosion problem until it is too late.

When corrosion is found on the surface of the pipeline, ultrasonic thickness measurement method can be used to detect the depth of the corrosion and, at the same time, detect if internal corrosion is also occurring at the same location where external corrosion has been found. Ultrasonic thickness measurement method is a very effective tool in determining local wall thickness of a pipe, but this method is limited to small areas and it takes a long time to use this method to inspect a large area of a pipeline. This method is mostly used to see the severity of corrosion defects when visual inspection shows occurrence of external corrosion.

In-line inspection (ILI) tools, or also called smart pipeline inspection gauges (pigs) travel through a pipeline scanning, measuring, and recording wall thickness, and looking for metal loss, dents, corrosion, deformations, cracking, or other defects [12]. Smart pigs use magnetic flux leakage (MFL) [13] or ultrasonic waves [14] to identify potential problems. The resulting data is then analyzed to diagnose issues and schedule maintenance. Most O&G companies use ILI technology every 3 to 5 years, thus, due to this long inspection interval, the ILI method cannot be considered as a health monitoring system, but instead as an inspection method. ILI testing involves production shutdown which is very costly, even when no corrosion is found during the ILI inspection.

Another technique used by the O&G industry to test pipelines for strength and leaks is hydrostatic testing [15]. This technique is particularly used to test newly laid pipelines for leaks. However, the same technique can also be applied to existing pipelines with defects and corrosion damage. The test involves filling a segment of a corroded pipeline with a liquid, usually water, which may be dyed to aid in visual leak detection, and pressurization of the pipeline to the specified test pressure. The test pressure is normally chosen higher than the working pressure to create a factor of safely. After shutting off the supply valve, the pressure tightness can be tested by observing whether there is pressure loss. The location of a leak can be visually identified since the water contains a dye and repairs can be performed if a leak or severe corrosion is found. Hydrostatic testing involves production shutdown which is again very costly.

To inspect insulated O&G pipelines for external corrosion, in addition to ILIs and hydrostatic pressure testing, the following three techniques are also used; Neutron Backscatter, X-rays or Radiography [16], and Pulsed Eddy Current [17].

In the case of the Neutron Backscatter method, the technique is not used to directly detect external corrosion of O&G pipelines but to detect presence of water underneath the thermal insulation. A radioactive source emits high-energy neutrons into the insulation. If there is moisture in the insulation, the hydrogen nuclei attenuate the energy of the neutrons. If presence of water under the thermal insulation is detected using Neutron Backscatter method, then, most likely, external corrosion under insulation (CUI) is occurring.

When thermal insulation is present, X-rays or Radiography method can be used to detect change in pipe wall thickness due to corrosion. Sections of the pipe wall, suspected of having corrosion, can be exposed to Iridium 192 or Cobalt 60 gamma rays, and the radiation transmitted through the pipe is captured using sensitive films. The sensitive film carries the image of the pipe section and the image can be used to calculate the remaining wall thickness of the pipe. This method is effective in detecting CUI, but it is limited to small area coverage. The radiation hazard to radiography personnel who perform the inspection is also of concern.

The Pulsed Eddy Current method is another inspection technique used to detect corrosion under insulation. Eddy currents are generated in the pipeline wall due to magnetic field produced by a coil. The coil-induced magnetic field is created by applying and controlling the electrical current to the coil. The thicker the pipeline wall, the longer it takes for the eddy currents to decay to zero. This property and technique are used to detect remaining wall thickness of pipelines.

All the techniques mentioned above, are inspection techniques. They are not able to provide real-time or on-demand corrosion monitoring for the O&G pipelines. As the above-mentioned inspection techniques are typically used once every few years, aggressive pipeline corrosion can occur in between inspection intervals without the knowledge of pipeline operators.

The demand for developing a corrosion detection sensor for O&G pipelines is ever increasing due to industry regulations and an aging pipeline network. The fact that most O&G flowlines cannot be pigged or are very difficult to pig, also plays a role in the demand for development of corrosion detection sensors that can be permanently deployed in the field. The industry is still in the search of a sensing solution that could be permanently deployed in the field, does not affect oil production, will be safe in volatile environments, cost-effective, require no or little power, and will not require any alteration or intrusion in the pipeline wall. Many of the existing inspection or health monitoring technologies violate the above-mentioned requirements, but our proposed sensor meets all the mentioned requirements as will be seen later.

Several sensors have been proposed for monitoring of pipelines based on optical fibers. Ren et al. [18] proposed to monitor hoop strain in the pressurized pipe, which will change as the pipe wall gets thinner due to degradation from corrosion or erosion. This solution is suitable for determining both external and internal corrosion [19,20], but it also involves removal of protective coatings and is sensitive to pressure fluctuations during pipeline operations. Lawand et al. [21] proposed a corrosivity sensor that can be placed in the vicinity of the exposed pipeline. This solution was based on Radio-Frequency Identification (RFID) technology and required an inspection crew to walk along the pipeline in order to interrogate each sensor.

In this paper, an external corrosion detection sensor, based on fiber optics and strain change, is proposed. It can be placed on the exposed O&G pipelines and interrogated remotely at any time. The size of the sensor is determined using Castigliano's second theorem and the sensor design equations are verified using the Finite Element Analysis (FEA) method. The sensor prototype was manufactured and tested in an accelerated corrosion test. The OBR 4600 Optical Back-scatter Reflectometer (OBR) was used as the fiber optic interrogator in the experimental apparatus.

The results obtained from the FEA, closed form equations, and the experiment show excellent correlations. Experimental results prove the feasibility of the proposed sensor. This sensor is able to provide corrosivity environment near the O&G pipeline and help prevent leaks by providing early warning for the operators to perform detailed inspection of a specific location on the pipeline.

The sensor is very safe as it involves only light traveling through the optical fiber. The only challenge is that the proposed corrosion sensor is unable to measure the corrosion rate in real-time, but it is able provide an average corrosion rate when the sacrificial metal element in the sensor fails.
