Pipeline Design

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The major steps in pipeline system design involve establishment of critical pipeline performance objectives and critical engineering design parameters such as:
• Required throughput (volume per unit time for most petroleum products; pounds per unit time for petrochemical feedstocks);
• Origin and destination points;
•Product properties such as viscosity and specific gravity;
•Topography of pipeline route;
•Maximum allowable operating pressure (MAOP); and
•Hydraulic calculations to determine:
•Pipeline diameter, wall thickness, and required yield strengths;
•Number of, and distance between, pump stations; and
•Pump station horsepower required.

Safety in pipeline design and construction is achieved by the proper design and application of the appropriate codes and system hardware components, as detailed above. Design codes as set forth in U.S. Department of Transportation’s (DOT’s) Office of Pipeline Safety (OPS) regulations provide appropriate safety factors and quality control issues during construction. Metering stations and SCADA systems provide continuous monitoring oversight of pipeline operations. Training of pipeline operating and maintenance personnel is also a key ingredient in the ongoing efforts to insure system integrity and safety. Safe operations result from developing and strictly adhering to standard procedures and providing the workforce with adequate training, safety devices, and appropriate personal protective equipment. Standard operating procedures typically are developed with reference to government and standard industry practices, as well as corporate safety policies, experience, philosophy, and business practices.
Regulations promulgated by the Occupational Safety and Health Administration (OSHA) and by counterpart agencies at the state level specify the procedures and controls required to ensure workplace safety, including, in some instances, the performance of process safety analyses and the development of very specific procedures for activities thought to represent potentially significant hazards to workers and the public.

Pipeline Coating
Corrosion-resistant coatings are applied to the exteriors of most pipes to inhibit corrosion. These may be applied at the manufacturing plant or a pipe coating plant located separately.
However, coatings are also sometimes applied at the construction site. Even for precoated pipe, field dressings of joints and connections are also performed at the construction site just prior to burial. For particularly corrosive products (including some crude oils with high total acid numbers), pipes are also sometimes coated on the inside for corrosion resistance. In addition to the resistance to corrosion they provide, some interior coatings are also designed frictional losses between the product and the interior walls of the pipe, thereby reducing the total amount of energy required to move the materials along the pipeline. Protective wrappings, followed by the application of tape to the edges of the spirally applied overlapping wrapping, are often installed on the exterior of the pipe to further assist in corrosion control, but also to primarily protect the pipe from mechanical damage at installation. Wraps and tape often are impregnated with tar or other asphalt-based materials and heated in place once applied, to ensure uniform coverage. Once cured, the exterior coatings are chemically stable and environmentally inert, resisting degradation by soil moisture and bacteria, yet remaining sufficiently flexible that they continue to provide a protective coating on the pipe throughout a wide temperature range.
Likewise, wrapping materials and tape are stable and inert (including toward the material being transported in the pipeline) and do not pose a potential for adverse environmental impacts.
Other coatings, such as thin-film epoxy and extruded polymers are also used as alternative to wraps and asphaltic coatings. Depending on local soil conditions, material of uniform size is sometimes imported to the construction site to form a bed on which the pipe is placed. The same material may also be installed around the sides and top of the pipe before the trench is filled with indigenous soils.
Such bedding material serves two principal functions: protection of the pipe from mechanical to reduce damage during installation and trench filling, and stabilization of the pipe in the event of seismic shifts or frost heaves. Sands and gravels are typical bedding materials and are tamped in lifts of 12 to 18 inches per lift to ensure adequate compaction and avoid future subsidence. Bedding materials also assist in draining accumulated water from the vicinity of the pipe.
All newly coated pipe used to transport hazardous liquids must be electrically inspected prior to backfilling to check for faults not observable by visual examination. Material faults such as microcracks demonstrate a characteristic response to applied current when the detector is operated in accordance with the manufacturer’s instructions and at the voltage level appropriate for the electrical characteristics of the coating system being tested.

The dimensions of a pipeline — both the sizes and capacities of the various components — as well as the conditions under which the pipeline system operates dictate the system’s capacity. Larger diameter pipes allow for higher mass flows of materials, provided other components of the pipeline system, primarily pumps and pressure management devices, are properly sized and positioned. In general, the longer the segment of mainline pipe between pump
stations, the greater the drop in line pressure. However, grade changes and the viscosity of the materials being transported can also have major influences on line pressures. API Standard 5L provides dimensions, weights, and test pressures for plain-end line pipe in sizes up to 80 inches in diameter. Several weights are available in each line pipe diameter. The weight of the pipe in lb/ft, in turn, varies as the wall thickness for a given outside diameter. For instance, API Spec 5L lists 24 different weights in the 16-inch-diameter size (five weights are special weights),
ranging from 31.75 lb/foot to 196.91 lb/foot. The corresponding wall thickness ranges from 0.188 inch to 1.250 inches. As the wall thickness increases for a given outside diameter, the inside diameter of the pipe decreases from 15.624 inches for the lightest weight pipe to 13.500 inches for line pipe weighing 196.91 lb/foot. Greater wall thicknesses are selected for high-pressure applications or when the pipe segment might be subjected to unusual external forces such as seismic activities and landslides.25 Also, in hard-to-reach places, such as beneath
transportation routes and at river crossings or difficult-to-access environmentally sensitive areas, overbuilding in size or quality is sometimes chosen to accommodate future expansion requirements.

Operating pressure of a pipeline is determined by the design flow rate vapor pressure of the liquid, the distance the material has to be transferred, and the size of line that carries the liquid. Pipe operating pressure and pump capabilities and cost typically drive decisions on line size, the number of pump stations, and the like. Grades notwithstanding, line pressure follows a sawtooth curve between pump stations. The maximum and minimum line pressure that can be tolerated, together with the physical properties of the materials noted earlier, dictate the spacing of the pump stations and the motive horsepower of the pumps.

Product Qualities
As noted earlier, critical physical properties of the materials being transported dictate the design and operating parameters of the pipeline. Specific gravity, compressibility, temperature, viscosity, pour point, and vapor pressure of the material are the primary considerations. These and other engineering design parameters are discussed in the following sections in terms of their influence on pipeline design.

Specific Gravity/Density
The density of a liquid is its weight per unit volume. Density is usually denoted as pounds of material per cubic foot. The specific gravity of a liquid is typically denoted as the density of a liquid divided by the density of water at a standard temperature (commonly 60°F).
By definition, the specific gravity of water is 1.00. Typical specific gravities for the distilled petroleum products gasoline, turbine fuel, and diesel fuel are 0.73, 0.81, and 0.84, respectively.

Many gases that are routinely transported by pipeline are highly compressible, some turning into liquids as applied pressure is increased. The compressibility of such materials is obviously critical to pipeline design and throughput capacity. On the other hand, crude oils and most petroleum distillate products that are transported by pipeline are only slightly compressible.
Thus, application of pressure has little effect on the material’s density or the volume it occupies at a given temperature; consequently, compressibility is of only minor importance in liquid product pipeline design. Liquids at a given temperature occupy the same volume regardless of pressure as long as the pressure being applied is always above the liquid’s vapor pressure at that temperature.

Pipeline capacity is affected by temperature both directly and indirectly. In general, as liquids are compressed — for example, as they pass through a pump — they will experience slight temperature increases. Most liquids will increase in volume as the temperature increases, provided the pressure remains constant. Thus, the operating temperature of a pipeline will affect its throughput capacity. Lowering temperatures can also affect throughput capacity, as well as
overall system efficiency. In general, as the temperature of a liquid is lowered, its viscosity increases, creating more frictional drag along the inner pipe walls, requiring greater amounts of energy to be expended for a given throughput volume. Very viscous materials such as crude oils exhibit the greatest sensitivity to the operating temperatures of their pipelines. However, in the case of crude oils, the impacts are not only from increases to viscosity, but also due to the solidification of some chemical fractions present in the oils. For example, crude oils with high amounts of paraffin will begin to solidify as their temperature is lowered, and they will become impossible to efficiently transport via a pipeline at some point.

From the perspective of the pipeline design engineer, viscosity is best understood as the material’s resistance to flow. It is measured in centistokes. One centistoke (cSt) is equivalent to 1.08 × 10–5 square feet per second. Resistance to flow increases as the centistoke value (and viscosity) increases. Overcoming viscosity requires energy that must be accounted for in pump design, since the viscosity determines the total amount of energy the pump must provide to put, or keep, the liquid in motion at the desired flow rate. Viscosity affects not only pump selection,
but also pump station spacing. Typical viscosities for gasoline, turbine, and diesel fuels are 0.64, 7.9, and 5 to 6 cSt, respectively.
As the material’s viscosity increases, so does its frictional drag against the inner walls of the pipe. To overcome this, drag-reducing agents are added to some materials (especially some crude oils). Such drag-reducing agents are large molecular weight (mostly synthetic) polymers that will not react with the commodity or interfere with its ultimate function. They are typically introduced at pump stations in very small concentrations and easily recovered once the
commodity reaches it final destination. However, often, no efforts are made to separate and remove these agents. Drag reduction can also be accomplished by mixing the viscous commodity with diluents. Common diluents include materials recovered from crude oil fractionation such as raw naphtha. Diluents are used to mix with viscous crude feedstocks such as bitumen recovered from tar sands and other very heavy crude fractions to allow their transport by pipeline from production areas to refineries.

read also Oil Pipeline Testing Methods

Pour Point
The pour point of a liquid is the temperature at which it ceases to pour. The pour point for oil can be determined under protocols set forth in the ASTM Standard D-97. In general, crude oils have high pour points. As with viscosity, pour points are very much a function of chemical composition for complex mixtures such as crude oils and some distillate products, with pour point temperatures being influenced by the precipitation (or solidification) of certain
components, such as paraffins.
Once temperatures of materials fall below their respective pour points, conventional pipeline design and operation will no longer be effective; however, some options still exist for keeping the pipeline functional. These include:
• Heating the materials and/or insulating the pipe to keep the materials above their pour point temperature until they reach their destination.
• Introduce lightweight hydrocarbons that are miscible with the material, thereby diluting the material and lowering both its effective viscosity and pour point temperature.
• Introduce water that will preferentially move to the inner walls of the pipe, serving to reduce the effective coefficient of drag exhibited by the viscous petroleum product.
• Mix water with the petroleum material to form an emulsion that will exhibit an effective lower viscosity and pour point temperature.
• Modify the chemical composition before introducing the material into the pipeline, removing those components that will be first to precipitate as the temperature is lowered. (This tactic is effective for crude oils, but is virtually
unavailable when moving distillate products that must conform to a specific chemical composition.)
Waxy crude can be pumped below its pour point; more pumping energy is required, but there is no sudden change in fluid characteristics at the pour point as far as pumping requirements are concerned. However, if pumping is stopped, more energy will be required to put the crude in motion again than was required to keep it flowing. When flow is stopped, wax crystals form, causing the crude to gel in the pipeline. If gelling occurs, the crude behaves as if it
had a much higher effective viscosity; consequently it may take as much as five to ten times the energy to reestablish design flows in the pipeline than it did to support stable continuous operation when the crude’s temperature was above its pour point.
For some products such as diesel fuels that still contain some waxy components (i.e., saturated, long-chain hydrocarbons), “gelling” may also occur as temperatures are lowered; however, such gelling problems are commonplace in storage tanks and vehicle fuel tanks where the fuel sits motionless for long period of time, but rarely materialize in pipelines where the materials are virtually in constant motion and where their passage through pumps typically imparts some amount of heat. Nevertheless, precipitation or gelling of products contained in
pipelines can cause significant operational difficulties and may also result in environmental impacts if pipeline ruptures occur during attempts to restart the flow, when a pressure well above design limits could result.

Vapor Pressure
The vapor pressure of a liquid represents the liquid’s tendency to evaporate into its gaseous phase with temperature. Virtually all liquids exhibit a vapor pressure, which typically increases with temperature. The vapor pressure of water increases steadily with temperature increases, reaching its maximum of one atmosphere pressure (760 mm Hg, or 14.7 psi absolute [psia]) at the boiling point (212°F).
Vapor pressures of petroleum liquids are determined using a standardized testing procedure and are represented as the Reid vapor pressure. Reid vapor pressures are critical to liquid petroleum pipeline design, since the pipeline must maintain pressures greater than the Reid vapor pressure of the material in order to keep the material in a liquid state. Blended (or “boutique”) vehicle fuels, required over some periods of the year for air pollution control
purposes in some parts of the country, have unique chemical compositions and unique Reid vapor pressures (as mixtures). Consequently, pipelines handling such fuels must constantly monitor their vapor pressure and adjust operating conditions accordingly. Pipelines carrying liquids with high vapor pressures can be designed to operate under a variety of flow regimes.
Single-phase flow regimes intend for the entire amount of the material in the pipeline to be in the liquid state. Operators of single-phase liquid pipelines attempt to control pressure and flow to maintain a “full face” of liquids in the pipeline, minimizing the amount of volatilization that is allowed to occur. This maximizes system efficiency and also the longevity of system components. Failure to maintain a full face of liquids in a single-phase liquid pipeline can result in increased risks of fires and explosions. Single-phase liquid pipelines are the most common designs for petroleum liquids. However, pipelines can also be designed as two-phase systems in which both vapor and liquid phases of the material are expected to be present. The variation of flow regimes in such two-phase systems can range from bubbles of vapor distributed in liquid to droplets of liquid suspended in vapor. Typical vapor pressures for gasoline, turbine fuel, and diesel fuel are 15, 2, and 2 psia, respectively.

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Reynolds Number
The Reynolds number, named after Osborne Reynolds, the scientist who first proposed its usefulness in studying fluid dynamics, is a dimensionless number that represents the ratio of the inertial force to the viscous force — that is, the ratio of the force moving a fluid to the force that attempts to resist that movement. In a pipeline, the inertial force is related to the fluid’s velocity, which is a function of the force applied to it by the pumps. The viscous force is a product of the inherent viscosity of the fluid as well as the frictional drag created by interaction of the fluid with
the interior surface of the pipeline. A low value for a Reynolds number (<2100) suggests that the fluid will be moved evenly, so-called laminar flow. Higher Reynolds numbers indicate that forces applied to a fluid are much greater than the forces resisting its movement; consequently its movement will be violent and turbulent. The Reynolds number representing the transition zone between laminar and turbulent flows is called the critical Reynolds number (Rcrit), which is typically assigned a value of 2320. The Reynolds number depends on the force applied by pumps, the material’s viscosity at operating temperature, and the physical size and cross sectional shape of the pipe through which the material is moving. Most pipeline designers select these components to establish operating conditions near Rcrit while still delivering the desired throughput.

Darcy Friction Factor
Named after the French engineer Henry Darcy, the Darcy friction factor is a dimensionless number that represents the linear relationship between the mean velocity of a moving fluid and the pressure gradient. The Darcy friction factor is critical in determining the necessary force capabilities of pumps as well as the spacing between pump stations to create the desired flow (and thus throughput) of a liquids pipeline.

1. Pipeline Engineering Handbook.
2. Pipeline Basics.
3. Design and Construction of Petroleum Pipelines.