IN SITU PIPELINE REHABILITATION TECHNIQUES, EQUIPMENT IMPROVED

Kuruvila Varughese
Al-Qahtani Pipe Coating Terminal
Dammam, Saudi Arabia

As many pipelines reach advanced age in the world's important producing regions and their corrosion protection systems fail, the prospect of their economic rehabilitation on site (in situ) becomes attractive.

Several projects to date have indicated this is feasible. But they have also revealed some problems that need solving and issues that need addressing.

Before covering these points and describing a successful rehabilitation project, a review of the role of coatings in protection and experience with them is in order.

CP AND COATING

Protective coatings help control pipeline corrosion by providing a barrier against reactants such as oxygen and water. But, because all organic coatings are semipermeable to oxygen and water, coatings alone cannot prevent corrosion. Also needed is cathodic protection (CP), which protects by providing a negative potential to the pipe surface.

However, the system's success depends on its ability to provide the electrons where and when required. Any obstacles to the working of the CP system, such as loose coating and submerged rocks, which prevent the electrons from reaching the pipe surface, can result in catastrophic pipeline failure. 1

Field experience confirms that the most economic and reliable corrosion protection system for underground pipelines is a combination of coating and cathodic protection. 2 But its success depends mainly on the ability of the coating to become an integral part of the "CP-coating" system.

The electrical resistance, adhesive strength, and cohesive strength of the coating are some of the properties that determine the ability of the coating to perform in unity with the CP system. Ideally, the coating should have good electrical resistance to minimize the current draw from the CP system. However, if the need arises for extra electrons at a localized area with higher concentrations of oxygen and water, the coating's electrical resistance should be low enough to allow the passage of electrons to protect that area.

The cohesive and adhesive strengths are two other important properties. The coating should have excellent adhesive strength and cohesive strength. But to be an effective part of the CP system, the adhesive strength of the coating must be higher than its cohesive strength.

This requirement can be easily understood by analyzing the behavior of the CP system on two pipes, coated with two types of coatings: one with higher adhesive strength and lower cohesive strength, the other with lower adhesive strength and higher cohesive strength.

When mechanically impacted, the coating with higher cohesive strength and lower adhesive strength will delaminate from the pipe surface without any break in the coating. Conversely, the coating with the higher adhesive strength will break and not delaminate.

Consider the role of the CP system in both cases. In the first case, where the coating delaminated without any break in the coating, the low CP voltage cannot pass through the unbroken, electrically resistive coating to protect the pipe. But in the case of the broken coating, where the electrical resistance is nonexistent, the low cathodic protection voltage can pass through the coating and protect the pipe.

In the first case, the delaminated, loose coating will become an obstacle to the CP system. This phenomenon, known as "cathodic shielding" and observed with coal tar and polyethylene systems, has been the primary reason for several underground pipeline failures.

Thousands of miles of pipelines laid in the 1960s and '70s under hot Middle Eastern conditions were externally coated with various polyethylene tape systems. Now pit corrosion, often with a metal loss of more than 40%, has been identified on many of them.

But a closer examination of many of these lines has confirmed that the pits are found only on isolated locations of the entire pipeline (Fig. 1). A major portion of the line is still in excellent condition. However, because of the potential for future leakage, these lines have to be either replaced or renovated.

Several years ago, the rehabilitation of underground pipelines with failed external coatings was not an economically reasonable option. Now, however, due to the combined efforts of the oil industry, coating manufacturers, and coating applicators, rehabilitation projects are economically viable.

REHABILITATION PROJECTS

Several pipeline rehabilitation projects have been completed worldwide, two in 1992:

A 1.2 mile section of a 34-in. diameter long distance gas transmission line near Kerrobert, Saskatchewan.
A 14.5 mile section of a 36-in. diameter long distance gas transmission line (Lufkin-Hungerford, Tex.) that was originally built in 1952.

Recently in the Middle East, two projects were completed by Al-Qahtani Pipe Coating Terminal, Dammam, Saudi Arabia.

The first was completed in 1992. It was a 24-in. diameter, 15.6 km (9.4 mile) section of a Saudi Arabian Oil Co. (Saudi Aramco) fuel gas fine. The second, earlier this year, renovated a 5 km section of the 48-in. Saudi Aramco oil line QJ-3 (Qatif Junction-3), which was laid in 1962.

The Middle East projects employed the same coating product used in the North American projects. The equipment was modified from the original design to accommodate the anticipated problems in the hot Saudi Arabian environment.

Even with this caution, many problems were encountered with the coating and surface preparation equipment due to dust and the high temperature of the pipe surface.

Even though the U.S. projects were claimed to be extremely successful,3 the initial stages of the first Middle East project were completed only with difficulty. However, the second project, the 48-in. diameter line, was completed successfully.

The success of this project was particularly important because it was the first time a large diameter pipeline greater than 42 in. in diameter was rehabilitated in place. This success was largely due to the changes made in the procedure based on the experience of the first project.

The experience from these two projects shows that a new approach is required by the industry to develop suitable coatings and application equipment in order to succeed with on site rehabilitation of high temperature pipelines.

Following is the Al-Qahtani rehabilitation procedure, which includes some of the modifications of the basic rehabilitation process as a result of this experience.

REHABILITATION PROCEDURE

There are several steps in the basic rehabilitation process. They include the removal of the old coating, inspection for metal thickness loss, surface preparation, coating application, and proper quality control tests. An accompanying article, p. 00, illustrates these steps and the equipment involved.

HYDROBLAST CLEANING

So far, the pipelines identified for rehabilitation were originally coated with polyethylene tape coatings. These coatings can be satisfactorily removed by a high pressure water jet (hydroblast) cleaning process.

Several companies have introduced different versions of the hydroblast units with water jet tip pressures varying between 14,000 and 30,000 psi. During the hydroblast cleaning, all old coatings and at least 90% of the old primer will be removed.

SURFACE PREPARATION

Most of the corrosion protection coatings require extremely clean surface (Swedish Standards Sa2 1/2) with an anchor profile of 1.5-3.5 mils. This is achieved by blast cleaning the hydrocleaned surface with an abrasive material.

Normally, blasting the surface with pressurized air (100-120 psi) carrying sand, flint, or a mixture of steel shot and grit of proper size can provide the required cleanliness and profile. However, the cleanliness and the profile greatly depend on the initial surface condition and the cleaning rate.

INSPECTION

A proper pipe surface evaluation is carried out after the surface preparation in accordance with the required specifications.

Metal thickness, cleanliness, contaminants, profile, etc., are checked. Joints with irreparable pits or unremovable contaminants are rejected.

COATING APPLICATION

Protegol 32-1OR, a coal tar polyurethane coating manufactured by TIB-Chemie, Germany, is the current specified product. This coating system consists of an epoxy resin mixed with coal tar and an isocyanate reactant.4

The base material is highly viscous at ambient temperatures. Therefore, before application, it is heated to about 130 F. to lower its viscosity.

The hot epoxy-coal tar base is then pumped to the coating spray head through a tube. Through another tube, the isocyanate is pumped to the application head, where both the isocyanate and the base are mixed and then sprayed onto the pipe.

Spray units with different gun configurations are available. The Al-Qahtani line travel coating spray unit consists of a circular head with two spray units attached to spray the coating material in opposite directions.

QUALITY CONTROL TESTS

After allowing sufficient time curing, the coating is tested for proper thickness, adhesion, holidays, etc. The test methods are in accordance with the coating manufacturer's recommendations.

COATING, SPECIFICATION

A product that is suitable for service must be available for the success of any coating project. Proper quality control tests are required to ensure the integrity of the coating.

Equipment for surface preparation and the coating application along with properly trained operators must also be available. Above all, a practical and technically sound specification is essential.

Because pipeline rehabilitation is a relatively new concept, many of these factors are in the developmental stage. This is particularly true for the rehabilitation of high temperature pipelines.

At present, coal tar polyurethane coating is the only field-proven coating system of the rehabilitation industry. This system was selected because of its fast curing and easier handling properties. All projects in the Middle East, U.S., and Canada have been completed with Protegol 32-1OR or its higher thixotropic version, Protegol 32-10RR.

These products are modified from Protegol 32-10, which has over 20 years of field history as an efficient corrosion protection coating. Similar products are also available from other coating suppliers. Some of the most promising products are currently under evaluation by the rehabilitation industry.

Even though Protegol 32-10R is fast curing and also has several advantages for field application, it has several limitations because it is a liquid. Surface irregularities such as runs, sags, and uneven thickness were some of the problems experienced with Protegol 32-10R coating.

It was reported that a coating of 24 mils with acceptable surface appearance was achieved with Protegol 3210R in the U.S. projects. However, this was not the case when the same product was used on the first Middle East project during the summer of 1992.

Even at 20 mil thickness, runs, sags, and drips were found to be at unacceptable levels. The thickness variation was unusually high. For a coating gun set-up of 24 mils, the coating thickness varied between 8 mils and 80 mils, at 3 o'clock, 6 o'clock, 9 o'clock, and 12 o'clock positions.

This lower thickness caused the rejection of several joints of pipe and unexpected project delays, Later the (coating application) gun set-up had to be changed to spray 50 mils to achieve the required minimum thickness of 20 mils.

RUNS, SAGS, DRIPS

Runs, sags, and drips all depend on the viscosity of the coating before it solidifies.

For a thixotropic coating, the viscosity is highly dependent on the thixotropic index (TI) and the substrate temperature. Because Protegol 32-10R is heated to about 130 F. prior to application, it will tend to run if the pipe temperature is above 130 F.

The extent of runs and sags will depend on the temperature differential of the coating and the pipe. During the rehabilitation project in the U.S., the pipe surface temperature was reported to be 130 F. for an ambient air temperature of 90 F.

Because the temperature differential was small, as expected, a lower level of runs and sags was experienced. But during the first Middle East project, the pipe surface temperature was 170 F. for an air temperature of 110 F. Because of the higher temperature differential compared to the U.S. project, the level of runs and sags was high.

The extremely low viscosity of the coating at the higher pipe temperature also caused the thickness variations that resulted in the rejection of several coated joints.

The parent formulation, Protegol 32-10, for line pipe was originally designed for factory application through a fixed spray system while the pipe is being rotated. But when this product was later modified as Protegol 32-10R for rehabilitation purposes (where the pipe is stationary), even though the thixotropic index was considerably increased, runs, sags, and thickness variations were high.

In order to minimize the runs and sags on hot pipe the product was further revised as Protegol 32-10RR, with some degree of success.

From field experience, it now appears that, due to the thermoplastic properties of coal tar, runs and sags, especially on high temperature pipelines, have to be tolerated for coal tar polyurethane products.

SERVICE TEMPERATURE

Two other areas of major concern with coal tar polyurethane products are the service temperature limitation and the cathodic disbandment (CD) property.

Coal tar is limited to a maximum service temperature of 80 C. For underground pipelines carrying low temperature products, this is acceptable. But this is not acceptable for high temperature pipelines. The cathodic disbandment property of the coating is also a key factor in selecting the coating for underground pipelines with cathodic protection.

At present there are no set cathodic disbandment value requirements for rehabilitation coatings. For the earlier projects, the cathodic disbandment value of the selected product was comparable to that of fusion bonded epoxy (FBE) coatings.

This is justifiable on the basis of the findings of a recent survey of corrosion coatings, which confirmed that the FBE coatings are the most preferred corrosion protection coatings for new pipelines.5

For most of the coal tar polyurethane systems, the reported cathodic disbandment test value at ambient temperature (ASTM G8-90 6 Test Method) is comparable to that of FBE coatings. However, the reported cathodic disbandment test values at higher temperatures (ASTM G42-90 7 Test method) are substantially higher than those of FBE coatings.

This may be due to the substantial change in the water permeability coefficient of the thermoplastic component of the system. But the effect of this reduced cathodic disbandment resistance on the long term performance of the coating has not been established. However, a better performance can be expected from a coating with better high temperature cathodic disbandment values.

CHLORIDES

The presence of chloride on the pipe surface will adversely affect the adhesion and cathodic disbandment properties of the coating. Fig. 2 shows the effect of chloride contamination on cathodic disbandment property of an FBE coating.

Similar results were observed with other coating systems, including the present rehabilitation coating, coal tar polyurethane. Therefore, to protect the coating against predesign life failures, the surface must be free of chlorides.

Even though a maximum tolerable level of chloride has not been established, the current acceptable level is 40 mg/sq m. Since the usual requirement of chloride testing on new pipe is limited, a practical chloride test for field use is not available. But for pipe buried under salty conditions, chloride testing is essential. Recently, Al-Qahtani Pipe Coating Research Center has evaluated several chloride tests to select a suitable method for the upcoming rehabilitation projects.

Out of many methods, "Aquamerck Chlorid," recommended by E. Merck, Germany, appeared to be the best for field conditions. Using this method, consistent chloride results were obtained by Al-Qahtani Field Construction Division during the field trials in Saudi Arabia.

Chloride contamination can be expected on pipe that has been in service in salty waters. To eliminate the potential chloride contamination, Al-Qahtani Pipe Coating Terminal has revised the rehabilitation procedure.

After the hydroblast cleaning, the pipe will be further cleaned with a sand blast cleaning unit. Subsequently, a chloride test will be conducted. joints with unremovable chloride contamination will be rejected. Accepted joints will finally be blast-cleaned with a recoverable grit blast unit. This procedure ensures a chloride-free pipe surface for coating application.

PROPER EQUIPMENT

Proper equipment is another factor that dictates the success of rehabilitation projects. The equipment must work reasonably well in the required environment.

This was one of the areas that caused many scheduled delays during the first Middle East project. The cleaning and coating equipment originally brought in for the project was not able to perform in the hot, dusty Middle East conditions. Several equipment modifications were required to complete this project.

After realizing the limitations, Al-Qahtani has modified and developed proper equipment to successfully complete rehabilitation projects for pipe sizes 14-26 in. and 36-48 in. under the Middle East conditions. Equipment for pipe sizes 26-36 in. is being developed.

A sound specification is still not available for the rehabilitation of high temperature pipelines. Since the coating and some of the equipment are currently under development, establishing a procedure now is rather difficult. The industry is waiting to establish a workable specification based on the experience of the two projects which were recently completed in Saudi Arabia.

CHALLENGES REMAIN

In corrosion protection systems involving coatings, proper selection of the coating is one of the key factors.

Even though excellent coatings such as Fusion Bonded Epoxies (FBE) are currently available for high temperature pipelines, most of them have several application requirements that limit them to factory application only.

With the current set-up, the on site, in situ rehabilitation process is limited to a spray-applied liquid coating.

Developing a coating system for rehabilitation projects is a difficult task because of the inflexible field application requirements. The coating must have a specific set of physical and chemical properties to suit the field conditions.

To achieve a reasonably good production rate, the coating must cure out faster, and it must be able to be handled within a few minutes without being damaged. The coating must also achieve proper cure to conduct adhesion, holiday, and other quality control tests within a reasonable amount of time.

Its viscosity must have a minimum temperature dependency to control runs, sags, and thickness variations. The coating's properties are further restricted due to the present method of coating application on a pipeline hung from side booms separated by a distance of 60-80 ft.

Even though the renovation of small sections of pipeline is not a new idea, the on site rehabilitation of the entire line in an economical way is a new concept. However, to achieve this, all disciplines of the industry must work together.

Even though remarkable progress has been made in pipeline rehabilitation within a short period of time, considerable challenges lie ahead for the high temperature pipeline on site rehabilitation process.

REFERENCES

Mills, G.D., "The Role of Pipeline Coatings in Mitigating Corrosion," Proced. International Conference in Organic Coating Science and Technology, Athens, Greece, July 1986.
Varughese, K., "The Role of External and Internal Pipe Coating and Linings in Potable Water Service," Al-Qahtani Pipe Coating Terminal Publication, 1988.
Derden, W., "One-Pass Pipeline Rehabilitation," Pipeline & Utilities Construction, July 1991.
Bogs, H.J., "Over the Ditch Tar Urethane External Coating Systems for Reconditioning of Pipelines," Proced. The European Pipeline Rehabilitation Seminar, London, May 22-23, 1990.
GRI, "State of the Art for the use of Anti-Corrosion Coatings on Buried Pipelines in the Natural Gas Industry," Topical Report, 1992, Gas Research Institute Transport and Storage Research Department, Chicago, Ill.
ASTM: C 8-90, "Standard Test Methods for Cathodic Disbonding of Pipeline Coatings." 1991, Annual Book of ASTM Standards, Sec. 6, pp. 1017-1025.
ASTM: G 42-90, "Standard Test Method for Cathodic Disbonding of Pipeline Coatings Subjected to Elevated Temperatures," 1991, Annual Book of ASTM Standards, Sec. 6, pp. 1078-1085.