Yulin Wu
Phillips Petroleum Co.
Bartlesville, Okla.
Efforts to evaluate problems associated with chemicals used in natural gas and NGL transportation and processing have lowered costs for one segment of an NGL system operated in Texas by Phillips Petroleum Co., Bartlesville, Okla.
Phillips' procedure consisted of two steps:
- Scientifically evaluating chemicals and the problems they generate
- Following experience and expertise in selecting chemicals and solving problems. If experience and expertise cannot be found or do not exist, Phillips conducts laboratory or field tests.
CORROSIVE CONDITIONS
With U.S. crude-oil reserves and production declining, gas and NGL have become a vital source of energy and raw materials for energy and chemical industries. This has led to the development and improvement of the processing and transportation of high quality gas and gas liquids.
The service conditions of such industrial facilities, equipment, and transportation, however, can be very corrosive. The gas-treatment process can also be very complicated and troublesome.
In order to secure a smooth process and provide corrosion protection, chemicals have been added into the systems. Unfortunately, these chemicals could also have an adverse effect and generate problems for the downstream operations. The costs of solving these problems have been expensive.
From oil and gas production through refining, the gas and NGL system consists of separators, heater treaters, gathering and discharge lines, gas pipelines, field and plant gas compressors, scrubbers, filters, receivers, amine treaters, caustic treaters, dehydrators, expanders, stabilizers, demethanizers, NGL storage, and NGL pipelines.
The refinery's process equipment is made up of treaters, separators, scrubbers, filters, reboilers, and distillers.
The equipment, facilities, and transportation lines are installed to process the gas and ensure that high quality gas and gas liquids reach the customers.
In order to protect the process equipment, facilities, and pipelines, and to obtain the highest gas and gas liquids qualities, the following chemicals are often added to the systems:
- Corrosion inhibitors
- Scale inhibitors
- Oxygen, CO2, and H2S scavengers: alkanolamines, caustics, bisulfites, etc.
- Antifoamers
- Demulsifiers
- Biocides
- Dehydration agents: molecular sieves and glycol
- Desulfurizing solvents: methanol
- Antifreeze: methanol and glycol.
CHEMICAL PROBLEMS
Unfortunately, these chemicals can also cause severe problems for the downstream operation if not properly selected and applied. And the chemically generated problems can be very costly for the systems.
In general, the problems are corrosion, plugging, and equipment fouling. The problems can also be generated from the products of decomposition, reaction, oxidation, and reduction of the chemicals in the systems.
For instance, a corrosion inhibitor can turn into a corrosive material if it is hydrolized in brine to form acidic compounds such as inhibitors with sulfonic acid and phosphoric acid derivatives.1 2
Corrosion inhibitor can also be decomposed or polymerized to form "gunky" and sticky material (Fig. 1) which eventually fouls systems with such inhibitors as dimer- and trimeramides, polyacrylic acid derivatives, etc.
Most corrosion inhibitors can cause foaming and emulsion problems in the gas-liquid or liquid-liquid reflux and separation areas such as in separators, glycol and amine treaters, stabilizer, or distiller.
The inhibitors, or other chemicals, can also be carried by gas or liquid hydrocarbons into treaters and dehydrators to shorten the service lives of desiccants (molecular sieves), glycols, alkanolamines, caustic, or filter components (Fig. 2).
Sometimes these problems become so severe that the systems need to be shut down or cleaned up. Products in the systems can be lost or damaged.
Degradation and reaction products of alkanolamines in the amine treater are corrosive.3 They are mostly polyamines, carboxylic acids, and heat-stable salts.
Most biocides are corrosive.4 For example, hydrochlorite, chlorine, and chlorine dioxide are corrosive or form corrosive by-products.
Some antifoams can become foaming agents if they decompose or are further polymerized in the treaters. These by-products and some of the high molecular weight antifoams could also be undesirable "gunkers," fouling the reboiler, heat exchanger, or compressor.
Molecular sieves in the dehydrator are the perfect catalysts for producing corrosive and undesired by-products, especially when they are impregnated with contaminants that contain transition metals such as iron, cobalt, nickel, platinum, chromium, molybdenum, vanadium, or palladium (Fig. 3).
In general, the following reactions could occur in the molecular sieves' bed: Olefin react with hydrogen sulfide to form mercaptan; sulfur is oxidized to form sulfur dioxide or trioxide, which is hydrolized to corrosive sulfurous or sulfuric acids.
Dimerization of mercaptans forms disulfides which are decomposed to polysulfur compounds.
Methanol is one of the most important chemicals used in the gas and gas-liquids systems. A large volume of methanol is constantly applied in the winter for preventing frozen lines in process facilities.
Excessive amounts of methanol in the systems, however, have cause corrosion problems due to the washing away of the established inhibitor film by methanol. Methanol has also directly and indirectly caused gunking, separation, and emulsion problems in the systems and refinery.
Some additives in chemicals can generate adverse effects in the systems. For instance, additives in methyldiethanol amine (MDEA) in the amine treater have increased the corrosion tendency in all environments as shown in Table 1.
The additives were added by the supplier to improve the efficiency of the loading and unloading of carbon dioxide and hydrogen sulfide in the amine treater.
By-products produced from oxidation of the chemicals are found to be extremely important when we consider the chemical effects in the gas and gas-liquids systems. By-product identification and effect on the systems are discussed in the next section.
OXIDATION PRODUCTS, EFFECTS
Oxygen from the air is becoming one of the major contaminants in gas and NGL systems.
The main sources of the contamination are leaks at the wellhead and vapor recovery at the tank batteries. The oxidation mechanisms of the chemicals by molecular oxygen are chemically known.
In most cases, however, the oxidation products in the systems are either unidentified or ignored. These products have threatened the corrosion and corrosion-inhibition programs in the systems.
There are many kinds of oxidation products depending upon the environments, temperatures, and chemicals involved. The most common oxidation products identified in the gas and gas-liquids systems are sulfur coming from hydrogen sulfide, carboxylic acids coming from methanol, glycols, alkanolamines and corrosion inhibitors, iron oxides coming from iron, polysulfides coming from mercaptans, amine oxides coming from amines, and thiosulfate coming from hydrogen sulfide and sulfur.
These oxidation products can be formed in the pipelines or carried over from treaters into the pipelines. They eventually cause severe corrosion in the pipelines. Phillips has experienced the problem in its pipelines. As shown in Table 2, corrosion rates of the brine samples are within the range of 3.0 mils/year (0.076 mm/year) to 30 mils/year (0.76 mm/year) which are considered to be medium-to-severe corrosion.
The brine samples were obtained from Pipeline G, sweet-gas Line D, PB discharge line, and Y line in the Texas Panhandle area, and were tested at 120 F. These lines were downstream of gas treaters.
Before the tests, the brine samples were degassed by purging with nitrogen and analyzed to determine their components. The analytical results showed that major components were brine and oxidation products that were carboxylic acids, mono and poly,amine salts, and sulfur compounds.
DESICCANT FOULING
Another example of the chemical fouling is the deactivation of molecular sieves by corrosion inhibitors, amine decomposition products, and oxidation products. Most of these compounds are long chain, high molecular-weight amine-based, or sulfide-based compounds such as amine-based inhibitors, fatty-acid derivatives, mercaptan, and disulfide compounds.
As indicated in Table 3, when these compounds came into contact with the molecular sieves, they were adsorbed by the sieves. Even in the molecular sieve high-temperature regeneration step, the adsorbed contaminants could not be totally burned off.
Finally, the molecular sieves were plugged and deactivated. When this problem occurred, the sieve's service life was cut from about 4 years to 8 months.
COST COMPARISONS
The costs for correcting the problems generated by the chemicals are higher than the costs of the chemicals themselves.
This may be due to the sudden and unexpected failures that occur with the chemicals in the course of the operations. This type of failure could spread into other interrelated units or operations.
Finally, the costs could be compounded. For example, heat exchanger tubes in the amine treater of a Phillips' plant in the Permian basin failed because of the severe corrosion caused by the additives in the amine solvent. The blended solvent was provided by the supplier.
As a result of the failure, hot oil contaminated the alkanolamine in the treater. The contaminated amine was eventually replaced by fresh amine with a total cost of approximately $260,000 in an 8-month operation period.
Normal chemical cost of the amine treater was approximately $60,000/year. This unexpected failure generated by the corrosion from the amine additives was about four times more costly than the amine itself.
Contamination of molecular sieves in a Permian basin gas plant's dehydrator has deactivated the dehydrator after 18 months' service. The costs were $35,000.
The normal service life of the molecular sieves is about 4 years with a total cost of about $21,500. The sieves' deactivation and failure were caused by the corrosion inhibitors and alkanolamine carry-over.
As indicated, the chemical problems and costs generated from these problems are interrelated. The more often chemical problems occur, either in the system itself or in the process operations, the more likely it is that costs of chemicals and operations can escalate.
Therefore, reducing chemical problems becomes essential because it could result in reducing the costs of the operation.
The way to reduce the chemical problems is, first, evaluate the chemical and understand the problems scientifically. The scientific approach in solving the problems is the key to success.
It could be chaotic if we only took advice from consultants or depended upon experts or suppliers to solve the problems or select chemicals for the system without going through scientific analysis, evaluation, and understanding.
Second, after the scientific evaluation, we should search for known experience, expertise, or case histories to solve the problems or select chemicals. This approach can save time and money.
It is unnecessary to "reinvent the wheel" if the way to the solution is available. If it is not available, laboratory or field tests certainly become necessary in order to satisfy the step of scientific evaluation and find a way to the solution.
Furthermore, to reach optimal success and problem solving, a good working relationship between the gas producer and chemical suppliers is essential.
The process for reducing chemical problems, therefore, can be defined as follows:
- Scientific evaluation
- Experience (case history, expertise)
- Test
- Solution.
The following three examples are listed to illustrate the importance and usefulness of the concept of reducing or eliminating the chemical problems in the gas and gas-liquids systems.
GAS PIPELINES
In previous years, the corrosion-inhibition programs for gas pipelines in the Permian basin very much depended upon the supplier's recommendations for inhibitor selections and applications. The inhibitor selections were based on the "pick and choose" concept.
The inhibitor's applications and inhibition effectiveness were measured by the quantity and viscosity of the inhibitors applied which is similar to the concept of "the more inhibitor the better" and a "sticky inhibitor is the best." If the corrosion inhibition were not effective, the more "gunky" inhibitor should be added.
As a result of these concepts, the effectiveness of the corrosion inhibition was poor in the region. In addition, the system was gunked up severely. The cost of inhibitors alone was more than $500,000/year.
In the recent years, inhibitor selection for this region has been based on scientific evaluation to identify the corrosive environments and components. This was then followed by laboratory screen tests to establish the type of inhibitor needed and level of the inhibitor concentration required to provide adequate protection.
As a result of this approach, corrosion inhibition for the region has improved substantially. The gunking problems have significantly decreased. The cost of inhibitors alone also decreased to about $230,000.
NGL PIPELINE
A 430-mile (692-km), 10-in. (25.4-cm) pipeline transports NGL's from the Permian basin to Phillips' Gulf Coast refinery.
In previous years, because of the corrosion problems in the Permian basin as just described, an iron sulfide precipitator was installed in the upstream pipeline to extract the corrosion product, iron sulfide, from the NGL.
Besides the iron sulfide precipitator, other equipment was also installed to support the precipitator, such as water wells, dehydrators, and disposal ponds.
Once again, the inhibitor for the line was selected by the supplier and applied in high concentrations. As a result of this program, total cost of the operations was about $1.3 million/year.
In recent years, the iron sulfide precipitator and its supporting equipment were totally eliminated. This change occurred after the following steps of scientific evaluation and field and laboratory tests were taken:
- Identifying the corrosive components and contaminants in the NGL.
- Studying physical properties of the NGL stream.
- Improving the upstream corrosion-inhibition programs (pipelines in the Permian basin) so that generation of corrosion product (iron sulfide) can be reduced.
- Screen-testing corrosion inhibitors to select the proper and most cost-effective inhibitor for the system.
It was found that the selected inhibitor could coagulate with iron sulfide in NGL.
The coagulated product would migrate into the water phase and was then separated from NGL by the water knock-out vessel.
As a result of these approaches, the costs were substantially reduced to about $200,000. The inhibitors concentration was also reduced to about 5 ppm based on total fluid.
NGL REFINERY OPERATION
In previous years, corrosion products and excessive amounts of corrosion inhibitors and other chemicals were carried by NGL's from the Permian basin into the Gulf Coast refinery. These materials fouled reboilers, heat exchangers, dehydrators, caustic treaters, coalescers, and distillers in the refinery.
In general, the NGL stream was 60% sticky organic materials combined with 40% corrosion products, mainly iron sulfide. These materials not only contaminated the treaters and fouled the equipment, but also caused operation downtime.
As a result, the cost of the operations each year was about $1.5 million.
In the past year, the cost of these problems has decreased because of improvements in the upstream operations, as just described in the two examples of gas and NGL pipelines.
In 1989, the costs of correcting the chemical problems were reduced to less than $500,000. The major expenses currently are the costs of refurnishing the filter from the coalescer filtration system.
TOTAL COSTS
Based on these three examples alone, the total costs of chemicals and chemically generated problems were about $3.3 million/year in previous years' expenditures.
This cost was reduced to $930,000/year when the concept of scientific evaluation was implemented to select chemicals and reduce the chemical problems.
REFERENCES
- Wu, Y., McSperitt, K.E., and Harris, G.D., "Corrosion Inhibition and Monitoring in Seagas Pipeline System," Corrosion/88, St. Louis, Mar. 21-25, 1988.
- Wu, Y., McSperitt, K.E., and Harris, G.D., "Corrosion Inhibition and Monitoring in Seagas Pipeline System," Materials Performance, Vol. 27 No. 12, pp. 29-33, December 1988.
- Comeaux, R.V., "The Mechanism of MEA Corrosion," 27th Midyear Meeting of the API Division of Refining, San Francisco, May 16, 1962.
- Preus, M.W., Lee, E.S., and Kissel, C.L., "Chemical Mitigation of Corrosion by Chlorine Dioxide in Oilfield Waterfloods," Materials Performance, Vol. 24, No. 5, pp. 4550, May 1985.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
