Corrosion Conditions in the Path of Bitumen from Well to Wheel

NACE 2012 Northern Area Eastern Conference, Toronto, Canada
October 28-31, 2012
Presented at the Symposium on Crude Oil Corrosivity
Paper Number: 2012-02

Sankara Papavinasam
Hamilton, Ontario, Canada

Parviz Rahimi
Devon, Alberta, Canada

Sandy Williamson
Ammonite Corrosion Engineering Inc.
Calgary, Alberta, Canada


This paper presents various operating conditions in the path of oilsands from the well to wheel and different types of corrosion that may take place at various stages. Though several types of corrosion may take place at other sectors, the possibility of corrosion in the oil transmission pipelines is low. The low corrosion possibility is due to the fact that the corrosive and erosive materials are removed upstream of the pipelines; the operating conditions of pipelines are mild conditions [(lower water content (typically less than 0.5% by volume) and lower temperature (typically less than 50oC)] in which the corrosive species (naphthenic acid and sulphur) do not influence corrosion.


Oilsand, corrosivity, erosion, upgraders, open mining, hydrotransport, SAGD, steam-assisted gravity drainage, oil transmission pipeline, and refinery.

1. Introduction

Oilsands are a naturally occurring mixture that typically contains 10-12 % bitumen, 80-85 % minerals (clays and sands) and 4-6 % water. Bitumen is a mixture of large hydrocarbon molecules containing up to 5% sulphur compounds by weight, small amounts of oxygen, heavy metals, and other materials. Physically, bitumen is denser than water and more viscous than molasses (sometimes existing as a solid or semi solid). Bitumen-containing oilsand deposits are found in over 70 countries, but three quarters of the world’s known reserves are in Canada and Venezuela. Oilsands represent about 66% of the world's total reserves of oil. Most of the oilsands in Canada are located in three principal deposits in Northern Alberta: Athabasca, Cold Lake, and Peace River; the deposits encompass nearly 77,000 km2 land area. The first Canadian oilsands mining operations started in 1967, the second began in 1978, and the third began in 2003. Currently several more mining operations are either under development or commercial consideration. In 2005, oilsands accounted for 50% of Canada's total crude oil output.

Oilsands are obtained by surface mining or in-situ production. The oilsands have to pass through several different processing stages before they can be sold to customers as refined gasoline or diesel, or other hydrocarbon feedstocks. This paper presents the operating conditions of the different stages and typical types of corrosion that can occur under those operating conditions.

2. Sectors in the Path of Oil from Well to Wheel

Table 1 presents typical paths for bitumen from open mining, bitumen from in-situ production, and paths for conventional crude oils. Table 2 compares characteristics of normal crude oil and bitumen. Tables 3 through 5 present typical operating conditions of various processing units and potential corrosion issues.

2.1. Open Mining

Surface mining is an efficient extraction method when the oil-bearing formation occurs within 80 meters from the surface. The oilsands used to be mined with draglines and bucket-wheel excavators; Truck-and-Shovel operations using large power shovels (100 or more tons) and trucks (400 tons) are the main method now used in the Athabasca oilsands area.

2.1.a. Hydrotransport Pipelines

From the mining area to the extraction facilities, the oilsands are transported either by conveyer belt or by hydrotransport pipelines for further processing. Since 2005 hydrotransport pipelines have been the predominant method for transporting oilsands. Hydrotransport pipelines are another variation of production pipelines. In general, transportation of solids in a liquid carrier stream is called hydrotransport. Introduction of the water and solid mixture into the pipelines is critical and is commonly performed downstream of the crushers. Slurry pumps then mix oilsands and hot water (90°C) to form stable slurries and introduce them into the hydrotransport pipelines. Large lumps of oilsands are broken down by mechanical forces during hydrotransport allowing some of the bitumen to be separated in the form of tiny droplets. Hydrotransport pipelines consume less energy (compared to conveyer belt transportation), but degradation of pipelines (erosion) by fine solids (clays), bitumen, and sands is a critical issue.

2.2. In situ Production

It is estimated that around 80% of Canadian oilsands and nearly all of Venezuelan oilsands are too far below the surface (i.e., deeper than 80 meters from the surface) to be accessed with open mining techniques. These oilsands are therefore extracted by in-situ methods. Some in-situ methods include cyclic steam stimulation (CSS), steam-assisted gravity drainage (SAGD), toe to head air injection (THAI), cold heavy oil production with sand (CHOPS), and vapour extraction process (VAPEX).

2.2.a. Cyclic Steam Stimulation (CSS)

Cyclic Steam Stimulation (CSS) to recover heavy oil has been in practice in California since the 1950s. CSS is often colloquially termed as a “huff-and-puff” operation. In this method steam is injected into a well at a high temperature (300 to 340°C) for an extended time frame (typically weeks or months). The well is soaked with steam for some period (days to weeks) in order to liquefy the bitumen and finally the heated bitumen (or extra heavy oil) is pumped out of the well. When the production of oil decreases, the cycle is repeated. The CSS method may recover 20 to 25% of oil in the formation, but the cost of injection of steam is high.

During the operation the temperature of the reservoir ranges between the steam temperature (at the injection point) and the reservoir temperature (at the production point). A major problem is the thermal expansion of equipment occurring when steam is injected. Therefore materials with suitable thermal expansion properties are selected for steam injection operation. The temperature in the producing wells is lower than in the injection wells. Therefore the thermal expansion is not an issue. Production wells are susceptible to abrasion because steam flooding produces excess sand. Critical areas of the equipment are frequently hard-faced to control abrasion.

2.2.b. Steam Assisted Gravity Drainage (SAGD)

Steam assisted gravity drainage (SAGD) process was developed in Canada in the 1990s. SAGD can recover up to 60% of the oil in the formation. In SAGD, two horizontal wells are drilled into the oilsand formation - one near the bottom of the formation, and another about 4 to 6 meters higher. The steam is injected into the formation via the upper well forming a steam chamber. The heat from steam reduces the viscosity of bitumen allowing it to drain to the lower well where it is flowed (under formation pressure) or pumped to surface. Progressive cavity pumps are commonly used to pump bitumen because of their compatibility with high-viscosity fluids containing suspended solids. Some small amounts of steam may be produced with the bitumen. The gases released (methane, CO2, and H2S) from the formation rise, filling the void space left by the oil and forming a thermal blanket

The SAGD infrastructure is predominantly constructed using carbon steel. Some equipment at the bottom of the underground tubing is constructed using 316-stainless steel. The SAGD infrastructure may suffer erosion and erosion-corrosion (due to the presence of solids), flow-accelerated corrosion (if the fluid velocity exceeds 5 to 6 m/sec), localized corrosion (due to condensing water containing acid gases on the inside surface of the casing and external surface of the production tubing), caustic embrittlement (threads of tubular connection if steam condensate containing caustic (sodium hydroxide) leaks through a connection), chloride stress-corrosion cracking (of 316 stainless steel components at the bottom of the production well), and crevice corrosion (if the connections are not properly threaded between tubular and injection wellhead).

2.2.c. Toe to Heel Air Injection (THAI) or Fireflooding (In situ combustion)

This method combines a horizontal production well and a vertical air injection well located near the most distal end of the horizontal well (the ‘toe’). This process works by igniting some of the hydrocarbons in the reservoir. The heat produced by combustion and the pressure partially upgrade the bitumen by in-situ thermal cracking (see section 2.5) and forces the bitumen towards the production well where it is pumped to surface. Over time, the active combustion zone progresses from the ‘toe’ towards the ‘heel’ of the horizontal portion of the production well. This process uses less water and produces less greenhouse gases than SAGD or CSS, but presents considerable challenge in controlling the underground combustion process. A related production process known as combustion overhead gravity drainage (COGD) uses the fire-flood concept but with a horizontal air injector creating a combustion zone above the horizontal producing well in a SAGD configuration.

The temperatures in the injection wells may be in the range 600 – 1200°F and the temperature in the adjacent production wells may reach a range of 200-350°F. The combustion gases (oxygen, organic acids, carbon dioxide, sulphides, and chlorides), steam, and temperature together create severe corrosion environment. Failures due to corrosion and erosion have been experienced in the casing, tubing, chokes, valves, and fittings of the producing wells.

2.2.d. Cold Heavy Oil Production with Sand (CHOPS)

Oil can be simply pumped out of the sands using subsurface progressive cavity pumps equipped with sand filters. The technique works only when the oil is fluid enough to flow at reservoir temperature. This technique is commonly used in Venezuela and in some oilfields in Canada. Although cost effective, this technique produces only 5-6 % of oil in the formation due to plugging of the formation near the sand filters and poor heavy oil mobility through the producing formation. Canadian companies have recently discovered that removing the sand filters from the wells and producing sand along with the oil can increase recovery rates to approximately 10% of in-situ reserves. This technique has become known as Cold Heavy Oil Production with Sand (CHOPS). Pumping sand oil out of the well creates additional fragmentation of the reservoir, which allows more oil to reach the production well. CHOPS produces large volumes of oil-soaked sand that can be used for laying roads and to reduce the dust during construction. Some amounts of produced sand are also disposed in underground salt caverns. Because of the volume of sand produced, erosion-corrosion is a major problem in the producing wells.

2.2.e. Vapour Extraction Process (VAPEX)

VAPEX is similar to SAGD in which a hydrocarbon solvent, instead of steam, is injected into an upper horizontal well to dilute the bitumen and allow it to flow into a lower horizontal well. VAPEX has higher energy efficiency than SAGD. This process is relatively new and corrosion mechanisms have not been established.

2.3. Extra Heavy Crude Oil Pipelines

Extra heavy crude oil pipelines are special types of production pipelines transporting crude oils with elevated pour temperatures or with high wax contents. They are normally used to transport bitumen or extra heavy oil for a short distance from offshore production platforms to oil processing facilities located onshore. Before entering into the pipelines the crude oils are heated to reduce the viscosity. Heat loss during transportation can allow wax or bitumen layer to form on the cool pipe wall decreasing the efficiency of the pipeline and, in extreme conditions, stopping flow. Similar to oil transportation pipeline operating conditions, corrosion is not a major issue for heavy crude oil pipelines.

2.4. Extraction, Froth Treatment, Tailing Plants

In the extraction plants, the oilsand is treated with hot water and is agitated, causing the oil to float as froth. The froth contains bitumen, water, and inorganic solids. Poor quality oilsand froths have lower oil contents and higher contents of water and solids. The froth is further treated to extract oil. In one process the froth is diluted with naphtha to decrease the density and viscosity of the bitumen and to promote coalescence of emulsified water; the mixture is then separated by centrifuging. In another process, a paraffinic solvent is added to the froth to reduce the bitumen density and viscosity and to promote flocculation of the suspended solids and promote water separation.

The extraction, froth treatment, and tailing plants handle large volumes of sand, operate at higher temperature and have more fluid movement. Therefore they suffer from erosion-corrosion and flow induced localized corrosion (FILC).

2.5. Upgraders

Refineries are designed to process only specific crudes. Bitumen from oilsands has a low API gravity, high viscosity, high sulphur content, high metal content, and high TAN number when compared to most conventionally produced oils. Bitumen does not meet the input requirements of some refineries (See Table 2). In addition, extra heavy crudes do not meet minimum pipeline specifications for transportation. In order to be transported through pipelines to the refineries the bitumen is either diluted or upgraded. The bitumen (obtained from extraction process) is diluted with naphtha, light synthetic crude oil, other light hydrocarbons, or natural gas condensates. The diluted bitumen is often called “dilbit”, “synbit” or “dilsynbit” depending on the material(s) used to reduce the viscosity and density of the bitumen in order to meet transmission pipeline specifications.

Alternatively, the crude oil may be ‘upgraded’ near the production facilities. Upgraders are essentially standard refinery elements that have been moved upstream to permit conversion of non-transportable bitumen into pipeline and refinery-ready crude oil. A variety of processes have been developed to upgrade heavy hydrocarbons to light hydrocarbons. Through upgrading, bitumen is converted into hydrocarbon streams – naphtha, light gas oil (LGO) and heavy gas oil (HGO) – that are blended to create transportable crudes, commonly called Synthetic Crude Oil (SCO). There are two basic steps in the upgrading process: primary upgrading and secondary upgrading. In primary upgrading sour crude (or crude containing more than 0.5% sulphur compounds) is produced and in the secondary upgrading sweet crude (crude containing less than 0.5% sulphur) is produced. Upgrading processes may include several units; some key units are described in the following paragraphs. Additional units may be used in the upgraders.

2.5.a. Atmospheric distillation unit (ADU)

Bitumen is a mixture of hydrocarbons with different boiling points. Distillation is a common process to separate them into various fractions. The temperature in the distillation towers varies, with the bottom of the tower being hottest and the top of the tower being coolest. The initial step in upgrading the bitumen is to remove naphtha in a simple distillation process. A charge pump moves the bitumen from the storage tank through a furnace where it is heated to temperatures up to 750°F and then to the distillation column. At various temperatures in the distillation unit the products are separated. For example, between 305o-325°F, both naphtha and kerosene distill out. The bottom residue from the ADU is sent to vacuum distillation unit (VDU). Table 5 lists the materials used in the ADU and typical types of corrosion occurring in it.

2.5.b. Vacuum Distillation Unit (VDU)

The residue from the ADU, while still hot, is transferred into the VDU where the pressure has been lowered below atmospheric pressure using a vacuum pump. At reduced pressure the lighter portions of the residue from the ADU will vaporize without cracking (splitting of larger hydrocarbon molecules into smaller molecules). The other components of the VDU are similar to those in the ADU. The vapors at the top of the VDU are condensed into heavy and light gas oils, kerosene, and naphtha. Vacuum distillation columns typically have diameters ranging up to about 14 meters (46 feet), heights ranging up to about 50 meters (164 feet), and feed rates ranging up to about 25,400 cubic meters per day (160,000 barrels per day). The residue from the VDU is used as feedstock in catalytic crackers, thermal crackers, cokers, or hydrotreating units.

Conversion of Canadian oilsands bitumen to SCO for the pipeline requires significant reduction in molecular weight and removal of heteroatoms indigenous to heavy oils. Other components such as chlorides and naphthenic acids are also present in bitumen and may cause problems during processing. Athabasca bitumen contains high concentrations of acidic components as indicated by its high TAN (Total Acid Number) of around 4–5 mg KOH/g oil. Naphthenic acids are primarily concentrated in the gas oil fraction of the hydrocarbon stream and can cause corrosion in vacuum distillation towers leading to significant upsets in the processing units. Detailed analysis of products from thermally treated gas oils using Fourier Transform Ion Cyclotron Resonance (FT-ICR) mass spectrometry has revealed that light naphthenic acids may be responsible for the majority of high temperature corrosion experienced in VDUs, and that heavier naphthenic acids may be relatively benign. Typical TAN testing does not differentiate between light and heavy naphthenic acids. Table 5 lists the materials used in the VDU and typical types of corrosion occurring in it.

2.5.c. Catalytic Cracking Unit (CCU)

In a catalytic cracker, heavy gas oil molecules are broken (cracked) into smaller hydrocarbons in the presence of catalyst under high temperature and high pressure. The main objective of catalytic cracking is to convert the heavy oil into gasoline. The temperature of CCU is maintained between 900 and 1100°F. A range of smaller molecules including methane, olefins, aromatics, naphthenes, residue, and coke are formed by this process. Table 5 lists the materials used in the CCU and typical types of corrosion occurring in it.

2.5.d. Thermal Cracking Unit (TCU)

Thermal cracking processes also break large hydrocarbon molecules into smaller molecules under conditions of high temperatures similar to CCU’s, but at somewhat lower pressure and without catalysts. The thermal cracking units (TCUs) have furnace and reactor chambers. The furnace is heated to temperature between 960°F and 1020°F. The heated feed is charged into the reaction chamber which is normally pressurized to about 100 psia to permit cracking. The products from the reaction chamber are cooled rapidly (or “quenched”) to stop the reaction process. The TCUs produce hydrocarbons similar to those produced by the CCUs and the products undergo similar treatment as those from CCUs. Table 5 lists the materials used in the TCU and typical types of corrosion occurring in it.

2.5.e. Coker

The coker unit converts the residual oil from VDU and ADU into hydrocarbon gases, naphtha, light and heavy gas oils, and petroleum coke. This process also cracks the long chain hydrocarbon molecules in the residual oil feed into shorter chain molecules. There are three types of cokers: delayed coker, fluid coker and flexi-coker. Table 5 lists the materials used in the coker and typical types of corrosion occurring in it.

2.5.f. Hydrotreating Unit (HTU)

Hydrotreating units remove chemically bound sulphur and nitrogen compounds from hydrocarbons. The purposes of removing the suphur and nitrogen compounds are to reduce sulphur dioxide (SO2) emissions and nitrogen oxide (NOx); to prevent poisoning of metal catalysts (platinum and rhenium); and to meet sulphur limits in kerosene and diesel. In the hydrotreating units, the hydrocarbon stream is mixed with hydrogen, heated to 500° to 800°F, pressurized from 450 to 2000 psi, and passed over a catalyst. Commonly used catalysts are cobalt and molybdenum oxides on alumina. Table 5 lists the materials used in the HTU and typical types of corrosion occurring in it.

2.6. Lease Tanks

After leaving the processing units (or separators), the crude oil enters lease tanks. Oil-water separators are used to ensure the crude oil is of sufficient quality to be shipped by pipelines. Often the crude oil is collected in the lease tank until its quality is checked. In manual operations, facility personnel measure and test the oil to determine if it meets the specifications set by the pipeline operators. Specific measurements include gross volume of product, temperature, and basic sediment and water (BS&W) content. If the tank products do not meet the required specifications, the contents may be rejected, reprocessed or blended until it again satisfies pipeline requirements. These measurements may be automatically evaluated by a lease automatic custody transfer (LACT, or simply ACT) unit.

Upon verification that the hydrocarbons meet specified quality requirements, quanta of product (called batches) will typically begin their journey to a designated refinery on a transmission pipeline system (see section 2.9). If the amount of crude being produced at a location does not justify the capital costs of building a pipeline to the lease, the crude may be hauled by truck or rail to a larger transportation center.

Lease tanks, tank cars, and tanker trucks may experience corrosion where water accumulates on the tank floor. The presence of acid gases (sour and sweet) and microbes increase the corrosion susceptibility. Many lease tanks, trucks, or tankers contain internal coatings to minimize their susceptibility to internal corrosion by providing a protective physical barrier to the water.

2.7. Waste water pipelines

Produced water is separated from crude oil at various points including at separators and oil-treatment facilities. Waste water pipelines transport the waste water to a disposal facility (underground or surface) according to site specific environmental regulations. Waste water is typically treated to remove materials including suspended solids, suspended oil, scales, bacteriological matter, and acid gases (CO2 and H2S). Selection of materials for surface facilities (pipe, valves, and fittings) to handle water for disposal depends on the pressure rating, the corrosivity of the fluid, the location, and economic cost over life. The materials used include cement, plastic, cast-iron, and carbon steel. Carbon steel pipes may suffer internal corrosion and this is normally controlled by excluding oxygen.

2.8. Tailing pipelines

Tailings pipelines are a variation of waste water pipelines. Tailings are a mixture of water, clay, silts, and finely ground sand that is left over once heavy oil is removed from oilsands. These tailings are deposited in containment ponds to limit residual oil from leaching into the environment. Providing safe, permanent storage of tailings is important because tailing materials that are not properly contained can have undesirable effects on the environment. From oilsands extraction facilities to the ponds, the tailings are transported in pipelines (tailings or slurry pipelines). Typically slurry pipelines are designed with a minimum velocity at which solids do not settle down (typically between 1.2 – 1.3 m/s); a maximum velocity at which erosion becomes the prominent issue (typically at 5 m/s depending on the particle size and density); a maximum slope that the pipeline can tolerate, and pumps and valves that are compatible with pipeline operations. The tailing pipelines may be susceptible to erosion and corrosion. The start of the tailings pipelines from the extraction plant have seen oxygen corrosion which leads to further metal loss due to erosion and corrosion.

2.9. Oil Transmission Pipelines

Transmission pipelines present the primary method of transporting hydrocarbons from oilfield production facilities to locations where they are used as fuels or where they are refined into higher value products. Transmission pipeline systems are often referred to as the “interstate pipelines” or “cross-country pipelines”. Pipelines are the most efficient mode for transportation of large quantities of crude oil. There are several advantages of transmission pipelines for transporting oil: transportation cost of pipelines is cheaper than other modes of transportation; the energy required to operate the pipelines is lower than that required to operate other modes of transportation; and pipelines are safe, reliable, and less sensitive to inflation as compared to other modes of transportation. Pipelines in general present the highest reliability of service over any other ground based transportation method, and transmission pipelines represent the best performing category of pipelines.

Liquid products are moved through pipelines by the differential pressure provided by pumps. Pumps are used along the pipeline to control both flow rate and pressure; as well as to overcome hydrostatic (elevation) pressure gradients. The total number of pump stations required to move crude oil long distances is determined through consideration of the maximum allowable operation pressure of the pipe, the hydrostatic pressure gradients along the pipeline, and the expected operating pressure drop along the pipeline. Transmission pipeline design represents a capital and operational cost balance between diameter, wall thickness, grade, energy costs, and pump facilities. For liquid pipeline systems, pump stations are typically located every 40 to 60 miles.

The operations of pipelines are strictly controlled within established normal operational conditions. With the advancement of automation and communication technologies, most pipeline operations such as starting and stopping pumps, opening and closing of valves, monitoring and evaluating pipeline conditions are carried out remotely under 24/7 oversight by specially trained control center personnel. Common control room operations include planning and scheduling operations, monitoring and controlling the pipeline, and responding to and correcting abnormal operations that may be planned (i.e, pigging or other pipeline maintenance tasks) or unplanned (i.e., automatic activation of safety devices).

Crude oil quality is important, since each crude oil type results in different refined products. Crude oil transmission pipelines have quality requirements. Most quality requirements are based on specific gravity and sulphur content of the crude oil. The density and specific gravity of the product is measured at injection and delivery points (custody transfer locations) of transmission pipelines, and at various intermediate locations for batch tracking purposes.

In multiproduct lines, different grades of crude oils move end to end in successive batches. When one product or type of crude follows another, some mixing inevitably occurs. This volume of mixed fluids is called transmix or interface material. Transmix materials are handled in various ways depending on their quality. The transmix is typically added to the batch of the lower grade crude, but may be segregated in a transmix receipt tank for separate processing.

The possibility of corrosion in oil transmission pipelines is low. This is due to the fact that the majority of corrosive and erosive materials are removed upstream of the pipelines as part of achieving transport quality specification (i.e., BS&W limit of 0.5% by volume). Additionally, transmission pipelines carry little or no CO2 or H2S, and they operate at temperatures too low for corrosive species such as naphthenic acid or sulphur to influence corrosion.

2.10. Refineries

Crude oils from the oil transmission pipelines are separated and refined into multiple product streams in the refineries. Oil refineries are large industrial complexes with extensive piping to transport different fluids between large processing units. The complexity of refineries depends on the type of crude oil being processed and the type of products being manufactured. Oil refineries typically process between 0.1 MMbbl and 2.0 MMbbl of crude oil per day into useful petroleum products. Because of this high throughput capacity, most refinery processing units are operated continuously. This high capacity makes process optimization and advanced process control very desirable.

The number and nature of the process units in a refinery determine its relative complexity. In general refineries are classified into simple refinery (containing crude distillation, catalytic reforming and distillate hydrotreating units); complex refinery (containing in addition to simple refinery units, catalytic cracker, alkylation plant and gas processing units); and very complex refinery (containing in addition to complex refinery units, a coker). Thus, depending on the nature of refineries several units may be present; some of the common units include a desalter, ADU, VDU, hydrotreating unit, catalytic reforming unit, CCU, TCU, hydrocracking unit, steam cracking unit, visbreaker unit (viscosity reducers), Merox (mercaptan oxidation) unit, coker, gas plants, alkylation unit, isomerisation unit, gas treating unit, sour water strippers, Claus sulphur plant (producing sulphur), heat exchangers, cooling towers, solvent extraction units, steam reforming units, polymerization unit, and pipings that connect several units listed above. Table 5 presents the materials used in different units of the refineries and common corrosion mechanisms in those units.

2.11. Oil and Product Storage tanks

Oil and products from the refineries are normally stored in aboveground steel storage tanks. The storage tanks act as a buffer between supply from refineries and demand from users. For example, gasoline demand is typically higher in the summer whereas heating fuel demand is typically higher in the winter. The storage tanks are built to store the refined oil from the refineries. Tanks are built as groups – commonly known as tank farms. Tanks can be as high as 14 m and as wide as 100 m. The tank size depends on average daily demand of oil, cycle time, safety stock, tank bottoms, and safe fill allowance. Cycle time is the time between the delivery of batches of a particular product. Oil tanks are covered with fixed or floating roofs to avoid evaporation and to minimize risk of fire. Similar to lease tanks, the storage tanks are susceptible to corrosion caused by accumulations of water or sediment on the tank floor. Virtually all modern storage tanks include a thick internal liner on the tank floor and walls to prevent contact between the metal shell and any accumulated water or sediment.

2.12. Product Pipelines

From the refineries or from the storage tanks, the products are transported to the product distribution centers or terminals. The product terminals are more widely distributed than refineries. Pipelines are the safest, most reliable, and cost-effective method of transporting the large volume of petroleum products. However, the capital cost associated with constructing pipelines limits their use to locations where very large volumes of product are to be transported for an extended period of time, typically over 15 to 20 years. Where the volume of petroleum products cannot justify the construction of a pipeline, petroleum products are transported to product terminals across land by trucks and rail cars and across water by marine tankers. Because the product is refined and the quality strictly controlled the possibility of internal corrosion is very low in product pipelines.

2.13. Terminals

Terminals are point where petroleum products are stored before final distribution to the customers. As a result of the significant reduction of terminals over the last 20 years, in some markets, only one terminal may exist in a city and all marketers store at that terminal. Each product has a different delivery system from the terminal depending on the customer base. For example, jet fuel is often moved by pipeline directly to the airport. Diesel fuel is distributed through retail outlets which are connected to the terminals. Vehicles can fill up at the retail outlets. Diesel may also be trucked to a distribution network (gas stations or petrol bunk), from which the customers can fill up. Gasoline, the most visible and widely used of all the oil products, has the most dispersed distribution network. Before the gasoline leaves the terminal, some retailers may add performance enhancing chemicals to distinguish their brand from others. The formula of the chemicals is confidential and unique to specific brand/company. Similar to lease tanks, the storage tanks suffer corrosion only if water is allowed to accumulate at the bottom.

3. Discussion

From the moment the drill bit or power shovel comes in contact with a raw hydrocarbon resource in its native environment, these natural resources are exposed to a wide range of temperatures, flow rates, transportation vectors, storage and processing conditions. These materials are incrementally cleaned, refined, and purified through a multitude of processes until they are eventually ready for sale to end consumers as useful fuels and lubricants, or until they are ready for sale as a feedstock for industrial petrochemical users. The myriad of conditions may present an equally varied potential for various forms of corrosion to take place, including general corrosion, localized pitting corrosion, intergranular corrosion, erosion-corrosion, flow-accelerated localized corrosion, corrosion fatigue, galvanic corrosion, high-temperature corrosion, and microbiologically influenced corrosion.

Although several types of corrosion may take place at the different stages of processing and transportation, the relative risk of corrosion generally decreases as the hydrocarbons are increasingly refined. Pipelines downstream of local processing present the lowest corrosion threat due to the fact that the corrosive and erosive materials are minimized; the operating conditions of pipelines are mild conditions [lower water content (typically less than 0.5% by volume) and lower temperature (typically less than 50°C)] in which the principal corrosive species (naphthenic acid and sulphur) do not influence corrosion.

While the high temperature and pressures of refining operations present the greatest potential for corrosion to occur, these processes are under the highest level of oversight and chemical and physical control. It is additionally noted that the total naphthenic acid content of certain crude oils may not translate into higher corrosion rates, as ongoing research has revealed that only certain species of naphthenic acids are corrosive under refinery conditions.

4. Summary

  • Between the wheel and well the crude oil is exposed to various operating conditions. These conditions have an influence on the type of corrosion that occurs.
  • In the presence of sand and velocity wear, erosion, and corrosion take place. Such conditions prevail in hydrotransport pipelines, upgraders, slurry pipelines, and waste water disposal pipelines operating upstream of the oil transmission pipelines.
  • The water content (typically less than 0.5% by volume), flow rate (typically less than 3 m/s), and temperature (typically less than 50°C) of oil transmission pipeline render them less susceptible to corrosion. Localized corrosion may occur in low-lying areas of the pipeline if water is allowed to collect and pool.
  • Naphthenic acid is not corrosive under the conditions of oil transmission pipelines.
  • In the refinery units present downstream of oil transmission pipelines, high temperature and high pressure operating conditions can exist. In these operating conditions naphthenic acid and sulphur can become corrosive.

5. Acknowledgements

The authors would like to recognize the valuable contributions of Trevor Place, Enbridge Pipelines and Bill Santos, CanmetMATERIALS in the preparation of this paper.


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Table 1: Comparison of Typical Oil Network of Conventional and Oilsands
Conventional oil network Oilsands Network – Open mining Oilsands Network – In situ production
N/A Truck and Shovel Excavation N/A
Drill Pipe N/A Drill Pipe
Casing Pipe N/A Casing Pipe
Tubing N/A Tubing
Downhole Tubular N/A Downhole Tubular
Acidizing Pipe, Water Treating, and Injection N/A Water Generators and Injectors
Wellhead N/A Wellhead
Production Pipelines Conveyor belt or Hydrotransport Pipeline Production Pipelines
Oil Separators Extraction, Froth Treatment, Tailings Treatment, Diluent Addition Oil Separators, Diluent Addition
N/A Tank Storage Tank Storage
N/A Upgraders Upgraders
Tank Storage Tank Storage Tank Storage
Waste Water Pipelines Tailing Pipelines Waste Water Pipelines
Oil Transmission Pipelines Oil Transmission Pipelines Oil Transmission Pipelines
Pump Stations Pump Stations Pump Stations
Oil Storage Tanks Oil Storage Tanks Oil Storage Tanks
Refineries Refineries Refineries
Product Pipelines Product Pipelines Product Pipelines
Terminals Terminals Terminals
N/A Diluent Pipelines Diluent Pipelines
Table 2: Characteristics of Normal Crude and Bitumen Derived Crudes

Bitumen Bitumen Derived Reference crude (West Texas intermediate)
Athabasca bitumen Cold lake bitumen Cold lake blend Sweet blend
Gravity, API 7.9 11.0 23.1 31.8 40.8
Specific gravity 1.0151 0.9928 0.915 0.8663 0.8212
Sulphur, Wt% 4.9 4.6 3.5 0.1 0.3
Nitrogen, ppm 4,000 3,740 3,230 630 800
Vanadium, ppm 222 182 152 <0.4 1.6
Nickel, ppm 87 65 57 <0.4 1.6
Asphaltene, wt% 17.5 16.0 13.4 0.1
TAN Number 3 1 0.8
Salt, lb/1000 bbl 40 20 15-20
Table 3: Operating Conditions, and Internal Corrosion Issues

Typical operating conditions Typical corrosion
Temp. °C Pressure, psi Water content, % CO2 content H2S content Chloride content Solid content, % Flow rate
Open mining Ambient Atmospheric Trace Vary Vary Vary 100 N/A Wear and erosion
Hydro-transportation pipeline 75-90 Elevated More than 50 Vary Vary Vary 35 3 to 6 m/s Erosion and erosion-corrosion
In-situ production See Table 4
Heavy crude oil pipeline 40-60 Elevated 1 to 5 Vary Vary Vary 1-5 3 to 6 m/s Corrosion when water precipitates
Extraction, Froth Treatment 75 Atmospheric 30 to 40 Vary Vary Vary 25 Turbulent Corrosion and erosion
Upgrader See Table 5
Lease tanks Ambient Atmospheric 1 to 5 Trace Less than 0.5% Vary 1-5 Stagnant Corrosion when water precipitates
Waste water pipelines Ambient Elevated 30 to 50 Below environmental regulations 10 3 to 6 m/s Erosion and corrosion
Tailings pipeline 75 Elevated 30 to 50 25-30 3 to 6 m/s Erosion and corrosion
Oil-transmission pipelines 25 – 30 1500 Less than 0.5 Less than 0.5 Less than 0.5 Vary Less than 0.5 3 m/s Corrosion when water precipitates
Refinery See Table 5
Oil storage tank Ambient Atmospheric 1 to 5 Trace Less than 0.5% Vary 1-5 Stagnant Corrosion when water precipitates
Product pipeline 25 to 30 800 Trace Nil Nil Nil Nil 3 m/s Corrosion when water precipitates
Terminal Ambient Atmospheric Trace Nil Nil Nil Nil Stagnant Corrosion when water precipitates

*Almost all units (except as noted in Table 5) are constructed from carbon steel

Table 4: Operating Conditions of Typical SAGD
Section*, # Temperature, °C Pressure, kPa Percentage water Percentage CO2, ppm Percentage, H2S, ppm Chloride, ppm
Injection tubing –top 235 5,000 ~95 as steam Carryover from steam generator Trace during circulation phase None
Injection tubing/casing annulus-top 235 4,000 ~95 as steam Carryover from steam generator Trace during circulation phase None
Injection heel to toe-inside injection string 235 2,750 90-92 as steam Carryover from steam generator Trace during circulation phase None
Injection heel to toe-outside injection string 235 2,750 90-92 as steam Some generated from reservoir Some generated from reservoir Some from formation water
Injection – intermediate casing annulus 8 to 235 2,750 90 – 92 Pipeline quality gas Pipeline quality gas None
Production toe to heel outside production string 230 2,700 Steam condensate ~7 - ~1,000
Production toe to heel inside production string 230 2,700 Steam condensate ~7 ~4 ~1,000
Production – gas lift string terminus 230 2,100 Steam condensate ~2 ~1 ~1,000
Production intermediate – casing annulus 6 to 230 2,100 Steam condensate ~2 ~1 None
Production tubing – top 230 800 Steam condensate ~2 ~1 ~1,000

*Relative flow: SAGD solution gas: 1 and SAGD lift gas: 8
#Most construction materials are carbon steel

Table 5: Refinery operating conditions*
Unit Material Temperature**, °C Pressure**, psi Corrosion rate**, mpy Typical corrosion type Effect primarily due to
Desalter Carbon steel 50 50 200 Localized pitting corrosion Salt
Atmospheric distillation Carbon steel, Cr-Mo steels, 12 Cr, 316 stainless steel, monel, and 70-30 copper/nickel alloy 371 50 315 Localized pitting corrosion, and flow-induced localized corrosion (FILC) Naphthenic acid and sulphur, HCl in overhead
Vacuum distillation Carbon steel, 9Cr-1Mo steel, and austenitic stainless steel 400 10 ~417 Localized pitting corrosion Naphthenic acid, sulphur, HCl in overhead
Catalytic cracking Carbon steel and stainless steel with refractory lining, Inconel 625, alloy 800 600 100 Intergranular SCC, graphitization, erosion
Thermal cracking 600 100
Hydrotreating Carbon steel, Cr-Mo steels, alloy 825, 321 stainless steel, 347 stainless steel, alloy 800, alloy 800H 670 2,000 ~137 SSC, SCC, Hydrogen flaking, Pitting corrosion H2S, polythionic acid, and ammonium salts
Hydrodesulfurization Carbon steel, 316L stainless steel, 405 stainless steel, alloy 825, 9Cr-Al, and graphitized SA 268 593 750 383 Intergranular cracking, localized pitting corrosion H2S
Catalytic reforming Carbon steel and 2.25 Cr 1 Mo steel 650 360 48 Metal dusting, carburization, and localized pitting corrosion Chloride, ammonia, caustic
Visbreaker Carbon steel 220 16
Coker Carbon steel 300 20 High temperature oxidation and sulphidation H2S
Alkylation Carbon steel, alloy 400, and Monel 400 188 60 100 Localized pitting corrosion SO2 and acid (sulphuric and hydrofluoric acid)
Gas treating Carbon steel 128 1,250 10 Localized pitting corrosion H2S, CO2, amine
Sour water stripper Carbon steel, 316L stainless steel,
alloy 825, Ni-alloy C-276, alloy 2205, alloy 2507 and grade 2 titanium
245 100 85 Localized pitting corrosion, erosion-corrosion H2S, flow, and chloride
Sulphur recovery Carbon steel, 304L stainless steel, refractory 121 16 Localized pitting corrosion H2S

*From papers presented at NACE STG 34 symposia between 1996 and 2011;