Judy S. Baum, Ken E. Marzocco
VECO Engineering Ltd.
Larry I. Hansen
Petro-Canada, Burrard Products Terminal
Port Moody, B.C.
Colin A. Brown
Trans Mountain Pipe Line Co. Ltd.
Sherwood Park, Alta.
- British Columbia, Albertia refinery closures, 1991-1996 [42,762 bytes]
- Refineries currently operating in British Columbia and Alberta [39,022 bytes]
Discussed here are the special design and operating considerations for terminal receipt of materials from a pipeline in both services.
Accurate interface detection and optimization of batch sizes and configurations are important factors in reducing operating costs. Dynamic modeling also proved useful in design optimization and minimization of operating costs.
Of the processes available to remove contaminants picked up by refined products moved through a crude-oil line, distillation is the most effective in lowering sulfur content and removing color bodies. If a product has no color specification, caustic treating is more economical than distillation.
ClosuresIn the past, crude-oil refineries were located near most major cities in the western Canadian provinces of British Columbia and Alberta. Crude oil was transported to the refineries in dedicated pipelines, then the refined petroleum products produced in the refineries were transported to sales outlets by truck, rail, and marine vessels.
Between 1991 and 1996, about half of the fully integrated crude-oil refineries in British Columbia and Alberta closed because of high operating costs and low economies of scale. At present, refined products from five refineries supply the areas' markets (Fig. 1 [65,691 bytes]). Approximately 85% of these products come from the three major refineries near Edmonton, center of Canadian crude-oil production.
Despite Edmonton's status, refined petroleum products consumed within a 200-km radius of Edmonton account for only a small portion of total demand for refined products in British Columbia and Alberta.
In order to meet the growing demand for fuel in other areas of the two western provinces, multiproduct pipelines now connect the main population centers.
Although trucking and rail cars can also be used to transport refined petroleum products, they may not be considered economical for large volumes and long distances. The cost of delivering a refined product from Edmonton to Vancouver via rail car is approximately three times that of a pipeline system.
Three multiproduct pipelines originate from the Edmonton area:
- Alberta Products Pipe Line. The city of Calgary lies 300 km south of Edmonton; at one time three crude-oil refineries served the area. High unit production costs forced these refineries to close, the last in 1992.
The Alberta Products Pipe Line, owned and operated by Imperial Oil Ltd., Toronto, was built to supply the Calgary area with refined petroleum products exclusively from refineries in the Edmonton area.
- Interprovincial Pipe Line. With its U.S. affiliate Lakehead Pipe Line Co. Ltd., Duluth, Minn., Interprovincial Pipe Line, Edmonton, operates the longest and one of the most complex liquid hydrocarbon pipeline systems in the world.
The IPL/Lakehead system moves 1.7 million b/d of liquid petroleum products from the oil producing areas of western Canada to refining centers and markets in eastern Canada and midwestern U.S.
- Trans Mountain Pipe Line. The Edmonton refineries supply the British Columbia market via a multiproduct pipeline owned and operated by Trans Mountain Pipe Line Co Ltd., Vancouver, the only major system in the world that transports refined petroleum products and crude-oil in a single pipeline.1 This innovative use of the pipeline has provided Trans Mountain's customers with the ability to reduce cost and improve efficiency in a highly competitive market.
From its construction in 1953 until 1983, Trans Mountain was solely a crude-oil pipeline serving Vancouver area refineries, as well as those in the Puget Sound region of Washington State.
In 1983, Trans Mountain began experimenting with refined-product shipments, which resulted in regular movements of refined products from Edmonton to Kamloops, B.C. (820 km), in 1985. By 1993, refined-product batches were routinely transported over the entire length of the system to Vancouver.
Fig. 2 [60,803 bytes] shows the multiproduct pipelines and refineries in operation as of 1997.
BatchingTrans Mountain pipeline travels approximately 1,260 km and crosses both the Rocky Mountain and Coastal Mountain ranges. The mountain terrain results in dramatic elevation changes that increase the challenges associated with minimizing contamination between the various products handled.
Fig. 3 [126,484 bytes] shows the route map for the pipeline system and the changes in elevations from Edmonton to the Pacific West Coast. The pipeline regularly transports crude oil and a wide range of products including jet fuel, gasoline (unleaded and premium unleaded), diesel (regular sulfur, low sulfur, and low temperature), methyl tertiary butyl ether (MTBE), and crude-oil (light sweet, light sour, and heavy).
Refined petroleum products move in the pipeline consecutively. Each distinct product is referred to as a "batch" and when several products are placed together in the line, they are called a "batch train."2
A typical refined-products batch train consists of a variety of products for different shippers and can be up to 350 km (220 miles) long. Crude oil is transported between refined-product batch trains. Fig. 4 [47,191 bytes] provides an illustration of a typical batch train.
As a batch train moves through the pipeline, adjacent products commingle, forming the "interface" zone. The extent of commingling, or the length of the interface, is a function of velocity, density difference between the two products, viscosity, pipe diameter, and distance traveled. Fig. 5 [56,561 bytes] shows a batch as it enters the pipeline and as it arrives at its destination.
Increasing the batch size can minimize product reprocessing; the amount of interface product remains constant regardless of the batch size. Consequently, the amount of reprocessing required relative to the quantity of the product received is important in minimizing cost.
The volume of product that can be placed in the pipeline, however, is limited by the tankage available at the receiving location, consumer demand for the product, and scheduling requirements for crude-oil deliveries.
As in any transmission system, there are many receipt and delivery points along Trans Mountain pipeline. Because of problems associated with product mixing, transportation of several products through a pipeline is more complex than moving an homogeneous product through the same pipeline.
Special procedures must be set up to minimize product mixing because products can be removed or added to the original batch as the batch train makes its way to the final destination. Additionally, such considerations as removing piping "dead legs," close coupling of lateral connections, and flushing idle pumps and piping are also important steps.
Pipeline and terminal operators have conducted extensive research and tests to develop systems and procedures to minimize rerefining required as the products leave the pipeline.
This research has shown, for example, that use of physical barriers (pipeline pigs) to separate products is ineffective with these system hydraulics and actually increases the level of contamination by creating additional turbulence.
On the other hand, research has shown that batching products in a particular sequence known as a "batch configuration" can hold product clean-up to a minimum.
Following are guidelines for setting up a batch configuration:
- Avoid placing next to one another products that are not miscible.
- Group similar product types sequentially. (That is, group all distillate products together.)
- Avoid placing next to one another two products with significant viscosity differences.
Once an established interface is formed, routing the products through the pump stations along the pipeline and interrupting the batch movement have relatively little effect on product mixing. Typical volumes for a diesel/gasoline interface arriving at Vancouver would be about 750 cu m (4,700 bbl) at normal flow rates.
Product downgrade occurs when the quantity of "contaminant" exceeds the maximum allowable for a given product. For example, when diesel is placed next to gasoline, it is important to segregate the interface formed between the two products to avoid degradations in product specifications.
After segregation, the interface material has to be reprocessed to yield saleable products. Common interface mixtures that require reprocessing include MTBE/diesel, diesel/gasoline, and jet fuel/gasoline.
Where the interface can be blended into one or both of the adjacent products, it is more profitable for a terminal operator to maximize the blending of the interface with the higher value product up to the limit of the product specifications. If the required specifications of a product are not met, the product will likely be downgraded, thus resulting in a loss of profit.
Apart from the handling of interfaces, other contamination issues such as the pickup of sulfur compounds and color bodies arise as a result of residual effects from the transportation of the crude oil. These issues will be addressed presently.
Interface detectionMinimizing product downgrade requires accurate determination of the interface between products and batch location. State-of-the-art technology combined with established procedures is currently employed by the pipeline and terminal operators precisely to identify the time to switch the valves that direct each product to the appropriate tank.
Following are technologies used in the interface detection:
- A densitometer measures the specific gravity of the product in the pipeline and can detect even minute changes in product density. For example, a densitometer can detect the difference in specific gravity between premium and regular gasoline.
A densitometer currently in use by a tank farm near Vancouver employs a smooth-bore pipe maintained in resonance by an electronic feedback system.
As the density varies, the product alters the vibrating mass which in turn changes the resonant frequency. The output signal can be easily transmitted and then processed without loss of accuracy with the latest microprocessor techniques.
- The sound-velocity interface detector employs changes in the sound velocity rather than changes in density to detect different liquids. At a constant temperature and pressure, sound will travel through a liquid at a unique, repeatable speed. A change in the liquid composition will result in the sound traveling faster or slower.
The unique sound signature associated with each petroleum product makes it is possible to differentiate two liquids that have almost identical densities.
- A continuous colorimeter detects color changes in the contents of the pipeline. It measures color quality with a dual wavelength, dual-detector optical system.
Measurements are performed by a continuous sample being drawn from the main process flow and a single beam from a halogen lamp being passed through the sample stream. Upon exiting the sample stream, the return beam is split and passed through optical filters.
Two independent photo detectors measure the intensity of the reference and measurement beams. The resulting signals are routed to the microcomputer where they are translated into a color measurement.
The colorimeter can be calibrated for a number of color scales including ASTM (D-1500) or Saybolt (D-156). Measuring the color of products entering the system during transit and at the delivery point permits product quality to be carefully monitored.
- Product batches are tracked throughout the entire pipeline. Information on the flow rate, pressure, temperature, density, pump status, etc. are collected by the pipeline supervisory control and data acquisition (scada) system and monitored in a central control facility.
This provides precise information as to the batch location, appropriate arrival time (?1 min), expected delivery rate, and timing for valve swings between products. These data are also used to model mathematically the entire pipeline and determine if any leaks exist.
Product-movement controlAt the terminals, batches are directed to the appropriate tanks at a rate of up to 360,000 b/d. During design of the terminal, a dynamic hydraulic model for optimizing control of product movements was developed that incorporated the tank-farm layout and other design data. 1
Flow, pressure, pipe size, and valve closures can be adjusted to determine such design considerations as piping configuration, valve-closure rates, product-contamination levels, back flow and vacuum conditions, and worst-case scenarios.
The model has been successfully used in developing the control strategy for directing the numerous products into the 16 receipt tanks connected directly to the multiproduct pipeline.
The data from the pipeline instruments are fed into a distributed control system (DCS) as input to a sophisticated computer model of the receiving terminal.
The DCS then controls the movement of the numerous motor-operated valves that direct the movement of the product within the terminal. Valve-closure rates are critical to prevent pipeline surge and product contamination.
It is essential that the sequencing valves be timed to ensure the pipeline movement is not restricted. Restricting the pipeline flow could result in the creation of a pressure wave that would cause a surge valve to open, thereby directing the pipeline contents to an off-spec tank. Fig. 6 [62,031 bytes] shows a flow schematic for the receipt tanks at a large product-receiving terminal in British Columbia.
As part of the operating procedure in receiving a batch at the terminal, an operator is expected to test the switching valves to ensure their operability before a batch arrives. Because of the importance of the switching valves, a two-tier backup system provides control of the operation of the valves.
In a power failure, a back-up generator supplies emergency power to operate the valves and an uninterruptible power supply (UPS) maintains the operation of the DCS. As a last line of defense, the valves can be operated manually.
Reprocessing methodsProper sequencing of the product batches and the use of interface-detection equipment can minimize but not eliminate product contamination. In addition to the mixing of products at the interface, refined products pick up elemental sulfur and color bodies from the walls of the pipeline during transit to the receiving terminals.
Several technologies are currently used in returning refined products to their original quality standards.
DistillationFrom the receipt tank, the contaminated product is pumped through a set of process heat exchangers and a direct-fired heater before it enters a distillation column where the product is distilled, causing the sulfur compounds and heavy hydrocarbons to accumulate in the column bottom (Fig. 7 [87,159 bytes]).
The reprocessed product leaves the top of the distillation unit as a clear overhead vaporous steam. The vapors are then condensed and collected in an overhead accumulator. A slip-stream of the condensed fluid is returned to the distillation unit as reflux.
Before the reprocessed product is sent to the finished product tank, the stream is passed through a set of zinc-oxide beds operated in series. The purpose of this final step is to remove any residual H2S that may have formed during heating and carried over with the finished product.
The stream leaving the bottom of the distillation unit contains concentrated levels of sulfur compounds and heavy hydrocarbons. This stream is recirculated to the distillation tower after it picks up heat in an external direct-fired heater.
A small fraction of the bottom stream, about 2.5%, is continuously bled from the system in order to control the contaminant levels in the system.
The main advantage of this process is that it can effectively remove both sulfur and color bodies picked up by the refined petroleum products during transit through the pipeline. In addition to polishing refined petroleum products, distillation is the only commercial process that is currently used to separate interface materials into their component parts.
Drawbacks associated with the system include a relatively high operating cost and process complexity.
Metal-oxide treatingMetal-oxide treating could be used as a standalone process. Under this operating scheme, sulfur-containing product from the pipeline would initially be transferred to a receiving tank.
From the tank, the product would be heated through heat exchange with the treated petroleum product and then in a direct-fired heater. Once heated, the contaminated product would be routed through two or more metal-oxide treaters, operating in series. The absorbent that would be selected is a combination of copper oxide and zinc oxide.
Studies have indicated that metal oxide can remove sulfur compounds from a refined petroleum product if the temperature of the process stream can be raised sufficiently to cause the elemental sulfur, disulfides, and polysulfides to become thermally unstable. This instability leads to decomposition and reaction with hydrocarbons to produce H2S and a mercaptide.
The reaction between some of the sulfur species found in the refined product and the absorbent used in the treaters would be irreversible. Consequently, the absorbent would have to be replaced once its sulfur-removal efficiency drops below an acceptable level.
The spent material could be sold as a high-grade ore to local smelters because of its metal contents.
The main advantages of using a metal-oxide treating system are its simplicity and its ability to handle sulfur excursions in the refined petroleum products delivered by the pipeline.
Drawbacks are that it does not address the color issue associated with refined-product contamination; and the absorbent has limited effectiveness because it can only remove the reactive sulfur species.
Caustic treatingExxon has patented several caustic-based processes for removing elemental sulfur from such refined petroleum products as gasoline, diesel fuel, jet fuel, and octane-enhancement additives such as MTBE.
The Exxon proprietary process currently employed by one of the terminals in British Columbia involves contacting the sulfur-containing petroleum product with a caustic-based solution. The main components of the patented process include an inorganic caustic material, water, an aliphatic mercaptan, and an optional sulfide.3
Mixing the petroleum product and caustic-based solution normally occurs at ambient temperature and pressure although higher temperatures and pressures may also be employed. Contact times vary widely depending on the product being treated, the amount of elemental sulfur contained in product, and the treating material used.
After thorough mixing of the petroleum product with the caustic-based solution, the mixture is allowed to settle to form an aqueous layer containing metal polysulfides and a clear fluid layer with a reduced elemental-sulfur level. The treated fluid may be recovered by decantation, and the aqueous layer may be recycled back to the mixing zone for reuse or disposal.
The main advantages of the process are that it can effectively remove elemental sulfur from refined petroleum products and it is less costly to operate than the distillation process. Drawbacks include provision for the disposal of spent caustic, inability to remove color picked up by the product during transit, and the need to obtain Exxon's consent for using the process.
FiltrationNormally used with other treating processes for removing contaminants from refined products, filtration may be the only treatment required with diesel. A typical system can be made up of a series of cartridge filters operating in series, parallel, or combination.
Once the diesel is filtered, additives such as corrosion inhibitors can be added to the petroleum product before it is directed to a finished-product tank. Because removal of contaminants with filtration is a physical process, the filter elements must be replaced when sufficiently loaded.
The main advantage of this process is that it is extremely simple. Drawbacks include limited use as a standalone clean-up system because it can only remove particulates and cannot be used to lower sulfur content or remove color bodies from the products. Additionally, the operating and maintenance costs along with the disposal of the filter elements can be costly.
References1. Mortimer, D., "Receipt Piping Hydraulic Study," private report prepared for Petro-Canada, Burrard Products Terminal, Port Moody, B.C., 1993.
2. Brown, C., "Life is a Batch: Transporting a Variety of Petroleum Streams in a Single Pipeline," presentation to the Natural Gas and Petroleum Technology Summer Institute, British Columbia Institute of Technology. Burnaby, B.C., June 19-21, 1991.
3. Falkiner, R.J., Poirier, M.A., and Campbell, I.D., "Process for Removing Elemental Sulfur from Fluid," U.S. Patent Number 5,250,181; 1993.
Judy S. Baum is a senior project and process engineer with VECO Engineering Ltd., Burnaby, B.C. Before joining VECO Engineering, she was employed by the process division of Westcoast Energy where she held various technical and line management positions.
She holds a BASc (1980) in mechanical engineering from the University of British Columbia, Vancouver, and an MBA (1995) from Simon Fraser University, Vancouver. She is a registered professional engineer in British Columbia.
Colin A. Brown is the supervisor of quality control and measurement for Trans Mountain Pipe Line and based in Sherwood Park, Alta. He joined Trans Mountain in 1985 and was assigned the task of developing the technologies to transport refined products in a crude-oil pipeline. He received his BS (1979) in chemistry from the University of British Columbia and is currently a director for the Canadian Crude Quality Technical Association.
Larry I. Hansen is supervisor of engineering and inspection at Petro-Canada's Burrard, B.C., terminal where he served as project coordinator for engineering design and upgrade for its receipt, storage, and processing of refined products from a crude-oil pipeline.
Hansen is a graduate of the British Columbia Institute of Technology and is a registered applied science technologist. He is a certified API inspector of pressure vessels and aboveground storage tanks and is a registered senior corrosion technologist with NACE.
Kenneth E. Marzocco is vice-president and general manager for VECO Engineering's British Columbia regional office. Before joining VECO, Marzocco worked for Petro-Canada as a project engineer responsible for engineering and construction of petroleum import and export facilities, tank farms, pipelines, and processing. He holds a BASc (1981) in mechanical engineering from the University of British Columbia and is a registered professional engineer in British Columbia.
Copyright 1998 Oil & Gas Journal. All Rights Reserved.