Multi-Product Pipelines are used to transport different hydrocarbon liquid products in batches in a single pipeline such as Diesel, Petrol, Kerosene and Jet Fuel.
Since the products transported in the pipelines are potentially hazardous to the environment and people in areas surrounding the pipeline, sound engineering standards and practices should be followed.
These design standards and considerations are crucial when designing, installing, and operating a multi-product pipeline.
Table of Contents
1 ASME B31.4
The American Society of Mechanical Engineers (ASME) B31 committee was originally established in 1926. The committee then introduced the ASME B31 code dating back to 1935. The code was developed and published by the American Society of Mechanical Engineers, the code is also maintained by them. The ASME B31 Code governs the rules and regulations for Pressure Piping systems. The code has been divided into different sections throughout the years, each governing a respective pressure piping system, some sections have been folded into others while others were superseded by other standards.
The ASME B31 code is currently divided into the following sections:
Power Piping, ASME B31.1,
Process Piping, ASME B31.3,
Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids, ASME B31.4,
Refrigeration Piping and Heat Transfer Components, ASME B31.5,
Gas Transmission and Distribution Piping Systems, ASME B31.8,
Building Services Piping, ASME B31.9, and
Hydrogen Piping and Pipelines, ASME B31.12.
The ASME B31.4 code contains important factors which must be considered. The latest published version of the ASME B31.4 code is 2016, the next edition is scheduled for publication in 2019. The 2019 version will take effect 6 months after the date of issuance.
1.1 Background – ASME Code B31 – Section B31.4
This section of the B31 code covers all minimum requirements for the most important factors of a pipeline transportation system namely: design, materials, components, fabrication, testing, inspection, operation, and maintenance. Transportation pipelines include all piping systems between the production fields or facilities including above or below ground storage facilities, refineries, processing facilities, pump stations, terminals, and tank farms. Section B31.4 also covers the pipelines transporting slurries of non-hazardous materials.
Also included in the scope of this section are: primary/associated auxiliary liquid petroleum and liquid anhydrous ammonia piping at pipeline terminals (marine, rail, and truck), tank farms, pump stations, pressure-reducing stations,metering stations, scraper traps, strainers, and prover loops.
Storage tanks, working tanks, pipe-type storage (fabricated from pipe and fittings), and piping interconnecting these facilities.
Liquid petroleum and liquid anhydrous ammonia piping located on property that has been set aside for such piping within petroleum refinery, natural gasoline, gas processing, ammonia, and bulk plants.
Aspects of the operation and maintenance of liquid pipeline systems relating to the safety and protection of the general public, operating company personnel, environment, property, and the piping systems.
The piping systems above consist of pipe, flanges, bolting, gaskets, valves, relief devices, fittings, and the pressure containing parts of other piping components. All materials must conform to specifications listed in tables as described in the ASME B31.4 code.
If the material is not listed in the above-mentioned tables, they must meet the requirements of the ASME B31.4 code for non-listed materials. It also includes hangers,supports, and other equipment items necessary to prevent overstressing the pressure containing parts. It does not include support structures such as frames of buildings or foundations.
Careful application of the ASME B31.4 standard will help users in the pipeline industry to comply with applicable regulations within their jurisdictions, while achieving the operational, cost, and safety benefits to be gained from the many industry best-practices detailed within this volume.
2 DESIGNING A PIPELINE
A certain process is followed when designing a pipeline transportation system upon selection of an applicable code, in this case ASME B31.4. The typical process followed will be discussed in this section.
2.1.1 Preliminary Planning
During the routing phase of a pipeline a preliminary planning process is followed and can be broken down into a few common aspects. The following aspects will normally be determined during the planning phase: the origin and the end destination of the pipeline, the product to be transported, the hydraulic factors such as the pipe diameter, and the type of flows expected in the pipeline. The approximate capital cost and running expenses will also be considered during the pre-planning phase although it does not pertain directly to the technical design of the pipeline.
2.1.2 Route Selection
The route selection of a pipeline can be done on various platforms, the route can typically be selected on a highway map, topographical map or on Google platforms such as Google Earth. It is good practice to obtain the most recent aerial photography to gather the required data for route maps and property plans. This data will be required for right of way acquisition.
2.1.3 Right of Way Acquisition
A thorough assessment of the proposed right-of-way and its surrounding natural environment is done to identify the unique features that must be protected throughout the life of the pipeline. It is quite a rigorous process to obtain the right of way of a pipeline and various considerations have to be taken into account. Some of the important considerations will be explained in more detail in the following subsections.
Analyzing environmentally-sensitive areas that need to be avoided, and having environmental experts complete an assessment on the entire proposed pipeline route. This process is known as an Environmental Impact Assessment, an abbreviation typically used in industry is EIA.
Determining who owns the land and what it is currently used for. The pipeline owners will typically engage with landowners to negotiate a sale or lease agreement to obtain the land on the proposed right of way.
Mapping out existing third-party infrastructure, such as underground structures, power lines, roads and railways. The infrastructure may be altered depending on the proposed right of way.
Working with local communities to understand their needs, concerns and plans.
Avoiding geohazards such as steep slopes, landslides and seismic faults. Elevation profiles is another important aspect that one has to take into consideration.
188.8.131.52 Road Access
Determining how construction and maintenance teams will access the area where the pipeline is buried after construction.
184.108.40.206 Local Communities
Identifying treaty lands, reserves or traditional land use.
220.127.116.11 Emergency Response
Determining the most efficient access for emergency crews and their equipment.
Studying seasonal variations in temperature and weather.
The final right of way of a pipeline will only be decided upon once all of the above considerations have been investigated and all problems are resolved. The route where the pipeline is buried after construction will now be known as the pipeline right of-way.
2.2 Pipeline Hydraulics and Line Sizing
During the pipeline hydraulic phase, the pipeline designer firstly determines the head losses expected in the pipeline transportation system. Secondly the designer will determine the pressures required in the pipeline to achieve an adequate flow to transport the fluid from start to end. The designer will make various assumptions to complete the hydraulic calculations. The assumptions will include selecting a pipeline size before conducting the calculations. This can be an iterative process until the calculations indicate an adequate size. A typical pipeline hydraulic calculation process will be summarized in this section.
2.2.1 Pressure Drop Equation
Considering the ASME B31.4 code which is relevant for liquid petroleum transportation systems the following assumption has to be made at the start of the process. It has to be assumed that the Fluid under consideration is incompressible and single phase.
The Pressure drop (ΔP) in the pipe is then calculated using the Darcy – Weisbach equation:
where, f is the Darcy friction factor, L is the length of the pipe, D is pipeline inner diameter, V is the fluid velocity and ρ is the fluid density.
2.2.2 Darcy Friction Factor
The Friction factor is a function of the fluid’s Reynolds’s number (Re) which is calculated as follows:
where, μ is fluid viscosity and D (Diameter), V (Velocity) and ρ (Density) is as derived above.
For Re < 2100, the flow is said to be laminar and the friction factor is calculated as follows:
For Re > 4000, the flow is said to be turbulent and the friction factor is obtained by solving the Colebrook White equation.
where, ε is pipe roughness based on the material of the pipe (which is assumed at this stage). Note that the Colebrook equation is an iterative process and 20 iterations is typically performed, this is at the designer’s discretion.
For 2100 < Re < 4000, the flow is in the critical zone or transition range between laminar and turbulent flow and there is no definite friction factor. The Churchill equation predicts a friction factor for the entire flow regime from laminar to turbulent, it is used to get an estimate for the friction factor in the critical zone. Note that all temperature dependent properties (density and viscosity) is assumed constant and will be taken at 15ºC for this example.
2.2.3 Fluid Properties
During the hydraulic phase the certain fluid properties in question needs to be taken into consideration, for example:
The designer will then list the applicable properties of the fluids in question, an example of such properties is illustrated in Table 1 below.
Table 1: Naphtha and Diesel Properties
Dynamic Viscosity (cP)
820 – 890
3.1 – 3.5
640 – 830
1 – 1.2
2.2.4 Hydraulic Analysis
Typical assumptions used during a hydraulic analysis are listed below. The assumptions are typically project specific and are chosen at the designer’s discretion. In many cases the client will state desired flow rates and pipe sizes, the designer will then run the calculations to confirm whether the client’s expectations are realistic and provide feedback.
Pipeline size: 18”
Pipe wall thickness: 9.53mm
Flow rate of product: 1000 m3/hr
Distance of Pipe: 6km
Pipe roughness: 0.046 mm
Oil Tanker discharge pressure: 10 barg
Maximum allowable pressure drop over the 6km: 8 bar (pipeline) and 2 bar Tank head
Maximum allowable velocity in the pipe: 4 m/s
Velocity at 1000m3/hr: 1.844 m/s
Assumed change in pipeline elevation: 6m
Table 2 is an example of the results of the calculations done by utilizing above equations and assumptions during the hydraulic calculations phase.
Table 2: Hydraulic Analysis
Dynamic Viscosity (cP)
Pipeline Pressure Drop (bar)
Tank Head Pressure (bar)
Total Pressure drop (bar)
Maximum flow @ ΔP = 10bar (m3/hr)
Velocity at max flow (m/s)
The designer will then conclude and make recommendations based on the results obtained. A typical observation based on the above scenario is that the flow rate of 1000 m3/hr is adequate for operation of all three products.
2.3 Material Selection
Once design conditions are established, piping can be specified. The first item to determine is what material to use. Different materials have different temperature limitations. Chapter III, section 423 in ASME B31.4 provides additional limitations for various pipeline materials. Material selection is also dependent on the system fluid, such as the use of nickel alloy for a corrosive chemical pipeline application, the use of stainless steel to convey clean instrument air or the use of carbon steel with high chromium content (greater than 0.1%) to prevent flow accelerated corrosion. The Carbon steel material is the most common selected material for pipeline transportation systems. Flow accelerated corrosion (FAC) is an erosion/corrosion phenomenon that has been demonstrated to cause severe wall thinning and pipe failure in some of the most critical piping systems.
The applicable material specifications and standards are summarized in the following two tables as extracted from the ASME B31.4 code.
Figure 1, Material Standards Table Extracted from ASME B31.4
Figure 2, Material Standards Table Extracted from ASME B31.4
2.4 Wall Thickness and Stress Calculations
Variables in these equations include maximum allowable stress, pipe outside diameter, material coefficient and any additional thickness allowance (as described below). With so many variables involved, specifying a proper piping material, nominal diameter, and wall thickness can be an iterative process that may also incorporate fluid velocity, pressure drop, and pipe and pumping cost. Whatever the application, it is necessary that the minimum required wall thickness be verified.
Additional thickness allowances may be added to compensate for several reasons, including FAC. An allowance may also be required to provide for additional strength to prevent damage, collapse, excessive sag, or buckling of pipe due to superimposed loads. Finally, an allowance may be added to compensate for corrosion and/or erosion. The thickness of this allowance is in the judgment of the designer and should be consistent with the expected life of the piping.
The minimum pipe wall thickness, or schedule, may not be constant over a range of pipe diameters and may require the specification of different schedules for different diameters. Corresponding values for schedule and wall thickness are defined in ASME B36.10 Welded and Seamless Wrought Steel Pipe.
When specifying pipeline material and performing the above calculations, it is important to ensure the maximum allowable stress values used in calculations match the material being specified. For example, if API 5L Grade B pipe were mistakenly specified instead of API 5L X42 pipe, the wall thickness provided could be insufficient due to the difference in maximum allowable stress values between the two materials. Similarly, the method of pipe manufacture should also be specified properly. For example, if calculations are performed using maximum allowable stress values for seamless pipe, then seamless pipe should be specified. If not, seam welded pipe may be provided by the fabricator/erector, which could result in insufficient wall thickness due to a lower maximum allowable stress value.
As an example, assume piping is sized for the following operating conditions, material, and product properties; summarized below and used in the example calculations to follow:
Max. Material and Product Design Temperature
Min. Material and Product Design Temperature
Pipeline Design Pressure
20 Bar = 2 MPa
Max. Operating Pressure
The material to be used for the pipeline example is API 5L PSL 1 Grade B or X42 and is either to be seamless or electric resistance welded (ERW). The mechanical properties of the pipeline material, except where otherwise stated, and table referenced throughout this example can be located in the ASME B 31.4 code.
API 5L PSL 1 Steel:
Minimum Specified Yield Strength (Table 402.3.1)
Maximum Allowable Stress
The Maximum Allowable Stress is calculated by using the following calculation as stated in the code:
The following properties account for both Grade B and X 42 steel:
8-inch (200 mm)
6-inch (150 mm)
Specified Pipe Wall Thickness as per API 5L 2004 Specification – Table 4
8-inch pipe, 8.2 mm
6-inch pipe, 7.1 mm
Density of Steel
2.4.1 Wall Thickness Calculations
The calculations that are required to establish wall thickness and allowable stresses are discussed in this section. The equations used to calculate wall thickness and allowable stresses are extracted from the ASME B 31.4 code.
The minimum pipe wall thickness is calculated by firstly calculating the thickness required for the pressure flow and then adding to it corrosion allowances. The corrosion allowance is specified as 0.5 mm/pa for 30 years by DIN 50929-3, table 8. The corrosion allowance used for the purpose of this example is 1.5 mm to increase life expectancy.
The wall thickness is calculated as follows:
Calculated for 8-inch pipe
Calculated for 6-inch pipe
Thus, the pipeline wall thickness of 8.2 mm as specified by the API 5L spec is more than adequate for the design pressure of 20 Bar.
2.4.2 Stress Calculations
The stresses that are induced on the pipe wall due to counteracting forces against internal pressure and thermal expansion are known as Longitudinal Stresses.
Calculated for 8-inch pipe
Calculated for 6-inch pipe
Modulus of Elasticity (E)
Linear Coefficient of Thermal Expansion Specification (∝)
6.5 × 10-6
Poisson’s Ratio for Steel (v)
It is thus necessary to equate the Hoop Stress first.
Calculated for 8-inch pipe
Calculated for 6-inch pipe
The allowable stress within the pipe is governed by the Maximum Shear Theory of Failure in ASME B 31.4. This theory states that the equivalent tensile stress shall not exceed 90% of the specified Sy of the pipe.
The above results confirm that the pipe design for the 8-inch and 6-inch lines adhere to the Maximum Shear Stress Theory of Failure.
The above calculations were done for Grade B steel, which has a lower allowable stress value compared to X42 steel. Therefore, the X42 steel will also be adequate.
2.4.3 Valves, Fittings and Equipment
As a general rule, per all valves, fittings, and other pressure-containing components manufactured in accordance with the standards listed in ASME B31.4 shall be considered suitable for use under normal operating conditions.
To simplify the design, the designer may choose to set design conditions conservatively high to meet the flange ratings of a certain pressure class (e.g. ASME Class 150, 300, etc.) defined by the pressure-temperature ratings for a particular material specified in ASME B16.5 Pipe Flanges and Flanged Fittings, or a similar standard listed in figure 1 and 2 contained in section 3.3 of this article, Material selection. This is acceptable provided it does not cause an unnecessary increase in wall thickness or other component design.
All equipment needs to be selected according to relevant pressure and fitting requirements, for example pump sets part of the pipeline transportation system.
2.5 Dimensional Requirements
This section of the code describes all standard and non-standard piping components. All piping components needs to adhere to certain dimensions to allow pipeline construction to be uniform. When flanged or threaded valves are taken into consideration it has to be noted that these components are all governed by the ASME B16.34 specification (this is only one example of dimensional requirements). This specification allows valve manufacturers to conform to certain dimensions; in turn this is taken into consideration when designing and constructing pipeline transportation systems which allow uniformity throughout the system. Dimensional standards are stipulated in the extract from the ASME B31.4 code below.
Figure 3, Table Summarizing Material Dimensional Specifications
2.6 Construction, Welding and Assembly
This section stipulates that new construction and any changes or upgrades to existing pipeline transportation systems shall be in accordance with the requirements as set out in the code. This includes the handling of pipe, welding, equipment, materials, and all the construction factors that will contribute to safety and sound engineering practice.
Detailed welding methods, procedures, and welder qualifications are stipulated in this section. The methods and procedures describe the amount of weld passes required on certain wall thicknesses. The acceptable butt-welded joint design section for equal and unequal wall thicknesses gives the user and indication how to bevel pipe ends to ensure adequate weld penetration. Safely crossing railroad or highways when constructing a pipeline is also described. The method to be followed when this obstacle has to be overcome is also detailed. The above summation is a brief one and it should be noted that all other requirements of this section are described in detail in the ASME B31.4 code.
Figure 4 Acceptable Butt-Welded Joint Design for Unequal Wall Thicknesses
Figure 6 Acceptable Butt-Welded Joint Design for Equal Wall Thicknesses
2.7 Inspection and Testing
A pipeline inspector has to have the correct qualifications when inspecting a pipeline installation, this section stipulates all requirements a quality inspector should adhere to. The pipeline installation should comply to the relevant material specifications, construction methods, and testing requirements stipulated in the ASME B31.4 code. The correct testing procedures are prescribed in this section, ex. the correct method to perform a hydro-pressure test and the parameters that need to be taken into account during this test. Various applicable nondestructive evaluations (NDEs) and the implementation thereof are prescribed to ensure full pipeline integrity.
2.8 Operation and Maintenance Procedures
The codes states that it is difficult to prescribe specific operation and maintenance procedures which will cover all cases for pipeline transportation systems. It is, however, possible for each operating company to tailor their own operation and maintenance procedures based on the provisions made in the ASME B31.4 code. The site-specific operations and maintenance procedures should always employ all relevant safety considerations.
2.9 Remaining Chapters of ASME B31.4 Code
It should be noted that the remaining chapters of the code will not be discussed in this article, though they should be referred to if necessary. The remaining chapters are:
Offshore Liquid Pipeline Systems
Carbon Dioxide Pipeline Systems
Slurry Pipeline Systems
During the route construction of a pipeline it is often required to cross certain roads, railways and/or certain natural occurrences like rivers or other types of water mass. The main types of crossings generally include the following:
Third Party Services
Roads and Railways
Other Forms of Water Mass
These crossings can be achieved through several methods. A detailed breakdown of the various types of crossing methods are discussed below.
3.2 Open Cut Crossings
Most minor water, road, and railway crossings can be achieved by open cut methods. These techniques entail the use of trenching technology. During open cut crossing establishments for a road, the trench is excavated across the road; therefore this application is mostly used for small, single track roads. The road will usually be closed temporarily as work proceeds. Once the pipe is installed the trench is backfilled to the appropriate level.
The open cut method for rivers and water mass is a bit more complex. The watercourse crossing is carried out by the introduction of damming and over pumping, or by the use of flume pipes installed in the watercourse bed. Figure 1 indicates the operation of flume pipes in open cut pipeline crossings over rivers.
Figure 1: Example of Flume Pipes (AquaDam, n.d.)
The site of the crossing is prepared by stripping topsoil from the banks and the flume pipe bridge is then installed. The flume pipes will be installed to take all of the flow. Excavation continues and often the method of pumping over the water is utilized to complete the trenching. The pipeline is then installed in the trench and backfilling is executed. The backfilling will be completed with excavated subsoil, free of large stones, using the stored river bed materials. The banks are then reinstated to their original condition, while the flume bridge and piping are removed.
3.3 Trenchless Crossings
Several trenchless crossing techniques exist, including:
Tunneling, including Pipe-Jacks
Horizontal Directional Drilling (HDD)
3.3.1 Auger Boring Method
The use of an auger bore is efficient with crossings of short to medium length (i.e. up to 120 m). This method of crossing entails the excavation of pits on either side of the crossing in order to assist with the installation of the pipeline. The type of crossing determines the depth of the excavations. Dewatering and sheet piling are safety measures that often need to be taken into consideration.
The pits that are excavated consist of a launching pit and a receiving pit on either side of the crossing. Additional land is frequently required to accommodate the excavations. An auger is then used in conjunction with a pipe string, where the pipe string is installed in the respective location, after lowering it into the pit by an overhead crane.
The Grundoram method is employed with short crossings such as drains, minor services, and minor roads, though it is more suitable to soft ground conditions. A pneumatic piston is used to drive a pipe from the launching pit to the receiving pit. The risk of settlement is low, when utilizing this method, as there is no overcutting of the tunnel during pipeline installations.
3.3.3 Tunneling Methods
Tunneling methods typically include:
Direct Pipe Installations
18.104.22.168 Pipe Jacking Method
This method is similar to the Grundoram method and involves ramming/thrusting an open-ended pipe underneath an obstacle. Mining and mechanical methods are used to remove the soil at the end of the thrust. Pipe Jacking is mostly used on very large diameter installations or in order to install a concrete carrier sleeve. The carrier will be of a much larger diameter than the pipeline itself and the welding and installation of the pipeline will then be done inside of the carrier. The pocket between the pipeline and the carrier will then be filled with grout once the pipeline is installed.
22.214.171.124 Microtunneling Method
Microtunneling is similar to pipe jacking and entails the use of a steerable remote-control pipe-jack. This method requires additional land due to the fact that the method requires a launching pit and a receiving pit. Management of drilling fluid will also be of concern with microtunneling.
Concrete jacking-pipes are placed at the rear of a microtunneling machine fitted with a cutting head. The cutting head will be lubricated with mud and water with the possibility of adding bentonite in order to lower friction further. The excavated material together with the lubricating slurry is removed through a slurry pipe. As the drilling hole progresses, extra segments of piping are attached from the launching pit until the concrete pipe reaches the receiving pit. The pipeline is then inserted into the precast concrete sleeve.
An alternative to microtunneling is the use of direct piping which utilizes the actual pipeline instead of a concrete carrier sleeve. The following image is a representation of microtunneling.
Horizontal Directional Drilling (HDD) is done by the drilling or boring pipeline underneath a crossing. resulting in the pipeline emerging at a target point at the opposite of the crossing. Large areas of land on either side is necessary to accommodate the equipment, drilling fluid management, and the laydown areas for the pipeline. A pilot hole is usually drilled and then enlarged to accommodate the actual pipe. Once the drilling operator is satisfied a “pulling” head is attached to the drill and the pipeline is then pulled through the tunnel. This method of crossings can be utilized for long crossings such as rivers or where multiple crossings are required, and trenching becomes infeasible. Figure 4 represents the operational procedure for an HDD crossing.
national grid. (2014). Crossing Methods. The Yorkshire and Humber (CCS Cross Country Pipeline) Development Consent Order.
4 ENVIRONMENTAL CONSIDERATIONS
There has been a rapid worldwide growth in the use of pipelines to transport a variety of products, but it is in liquid fuel and gas where they have gained prominence. Pipelines are the most environmentally friendly way to transport a variety of products all across the world, as they are more effective and efficient in transporting products than their alternatives. The importance of pipeline transportation is hardly recognized, due to the fact that most pipelines are buried underground. Some may think that underground pipelines are not associated with environmental problems, but the risk of improper management is always present. Today pipeline operations are relatively safe, but it is important to keep in mind that the risk of disruptions will always be there and may occur. Acknowledging the potential for risk means acknowledging the possibility that disruptions and occurrences can take place which may have a severe impact on both the pipeline, it’s supply, and the environment.
Multi-product pipeline transportation products such as fuel and oil have a direct impact on the environment, if not managed correctly with effective risk assessment, these impacts can become very harmful to the natural environment. Due to the nature of the products transported via pipelines, and the risk of disruptions (leakages, spillages, and explosions) the importance of environmental monitoring and environmental management cannot be overemphasized. Any Legislation regarding pipelines or Linear activities must give effect to the principles of the National Environmental Management Act 107 of 1998 (“NEMA”) paired with Listing Notices 1, 2 and 3 which delineates thresholds for each activity. The latter binds the actions of all organs of state that may have a detrimental effect on the environment. These principles apply the constitutional rights in a practical, environmental context, serve as the framework within which environmental management and implementation plans are to be formulated, and serve as guidelines for any organ of state exercising any function concerning the protection of the environment. The NEMA principles therefore clearly apply to all regulation and decisions regarding pipeline activities in order to minimize any potential risk to the environment. NEMA serves as a guideline to enhance sustainable development when it comes to pipeline construction.
By applying the South African NEMA principles it will help to determine:
Whether a Full Environmental Impact Assessment (EIA) or a Basic Environmental Impact Assessment (BA) is required by identifying which activities are triggered under Listing Notice 1, 2 or 3, were Listing Notice 1 and 3 indicates a BA and Listing Notice 2 a full EIA.
Whether or not an activity will have a positive or negative impact on the environment. Ensure that these impacts are carefully evaluated in order to protect the environment as well as the quality of life regarding human life and species in the vicinity and beyond.
If the activity contributes to sustainable development
Which specialist studies needs to be conducted
The NEMA principles relating to sustainable development state:
The disturbance of ecosystems, loss of biological diversity, environmental pollution and degradation, waste and the disturbance landscapes and cultural heritage sites must be avoided (or, where these impacts cannot be altogether avoided, that they are minimised and remedied).
The use and exploitation of non-renewable natural resources must be responsible and equitable taking into account the consequences of resource depletion.
The development, use and exploitation of renewable resources and the ecosystems of which they are part must not exceed the level beyond which their integrity is jeopardised.
A risk-averse and cautious approach must be applied which takes into account the limits of current knowledge about the consequences of decisions and actions (the “precautionary principle”).
The negative impacts on the environment and on people’s environmental rights must be anticipated and prevented (or, where these impacts cannot be prevented, they are minimised and remedied).
As more pipelines are proposed around the world, concern grows regarding their impact on the landscape. Wetlands, in particular, will always be a challenge when it comes to pipeline construction. Wetlands are generally considered important habitats on account of the roles that they perform in an environment. Typically, a wetland area can be defined using a combination of three key parameters (Wetlands Delineation Manual, US Army Corps of Engineers 1987):
Soils are present and classified as hydric, or they possess characteristics that are associated with reducing soil conditions.
The area is overwhelmed either permanently or periodically at mean water depths of ≤ 2m, or the soil is saturated to the surface at some time during the growing season of the prevalent vegetation.
The prevalent vegetation consists of macrophytes that are typically adapted to areas having hydrologic and soil conditions described in the preceding definitions. Hydrophytic species, due to morphological, physiological, and/or reproductive adaptation, have the ability to grow, effectively compete, reproduce, and/or persist in anaerobic soil conditions.
Effectively, the construction of pipeline through wetland areas require the use of a combination of techniques and methods that will be used as a standard along the rest of the pipeline route. These are specifically designed to minimize impact within hydrologically and ecologically sensitive areas. The objective of pipeline development should be to ensure that the construction process incorporates the measures required, ensuring the continued integrity of the wetland habitats along the route. Pipeline design and construction should include measures to protect wetlands areas and to minimise the impact on the environment, and all living organisms that may be affected by the pipeline construction.
Many times pipeline construction will commence and half way along the route a endangered specie will stop construction. A endangered species could stop a pipeline construction for months and sometime decommission the entire project, therefore the correct specialist studies need to be conducted before construction commences.
There are many environmental aspects that could affect a pipeline project, therefore the correct measures need to be taken beforehand to identify all the possible challenges. An Environmental Impact Assessment (EIA), if done correctly, will address all of these challenges.
Public participation is one of the major challenges during an EIA for a pipeline project. Public participation is an important requirement during all Environmental Impact Assessment Processes and could possibly be the most difficult phase of the entire assessment process. Under section 33(1) of the Constitution, everyone has the right to administrative action that is lawful, reasonable and procedurally fair. The NEMA principles require decision-making in an open and transparent manner with access to information provided in accordance with the law (NEMA section 2(4)(k)). This requirement applies the constitutional rights to access to information and just administrative action. This phase requires that the assessment practitioner liaise with all Interested and Affected Parties (IAP’s) especially with those affected along the pipeline route. In most cases farms and heritage sites are affected along the route and farm owners could delay the impact assessment process due to certain risks that could damage their farm in several ways. Once again, sustainable development is very important during pipeline construction.
Section 32(1) of the Constitution provides that everyone has the right of access to (a) any information held by the state and (b) any information that is held by another person and that is required for the exercise or protection of any rights. The public’s access to information determines whether all stakeholders are able to participate in those decisions affecting them in any meaningful way and acts as a check on administrative actions. Because of the many stakeholders likely to be fundamentally affected by a pipeline development, it is particularly important that all stakeholders are provided with complete relevant information to allow for informed and impartial decision-making during the process. It is important that the project gains the trust of the public. In other words, to ensure that the IAP’s are involved in every step of the process.
5 LEAK DETECTION
The integrity of pipelines presents challenges that are quite unique. Their long length, high value, high risk and often difficult access conditions, require continuous monitoring and an optimization of maintenance interventions. The main concern for pipeline owners comes from possible leakages that can have a severe impact on the environment and put the pipeline out of service for repair
5.2 Pipeline Leak Causes
Leakages can have different causes, including excessive deformations caused by earthquakes, landslides or collisions with ship anchors, corrosion, wear, material flaws or even intentional damage. Other causes include but not limited to;
Fatigue cracks are one cause, these occur as the result of material fatigue and are often found on longitudinal welds.
Tensile strength can cause stress tears which can reduce the effectiveness of Cathodic corrosion protection systems, resulting in corrosion on the pipeline.
Cracks can also be caused by hydrogen indexing. In this case, atomic hydrogen diffuses into the metal grid of the pipe wall, forming molecular hydrogen. This can lead to the pipe material becoming brittle and prone to early failure.
Material manufacturing errors can also cause leaks, e.g. when cavities are rolled into the material during production of the pipe.
Leaks can also occur when an external force acts from the outside;
The cost of failure to detect the leaks results in;
Loss of life and property
Direct cost of loss products and lie downtime
Environmental clean-up costs
Possible fines and legal suits
Pipeline leak detection systems can be categorised into two major types; continuous and non-continuous systems.
Leak Detection System
Inspection by helicopter
Fibre optic cable
Pressure point analysis
Mass/Volume balance method
Non-Continuous Leak Detection systems
Inspection by helicopter
The helicopter flies along the pipeline, looking to detect any outflowing gas. Three common methods when detecting leaks by helicopter include detection using Laser, Infrared cameras and “leak sniffers”. When using lasers for leak detection, a laser is set to the absorption wavelength of the medium to be detected. When the laser hits the medium, a part of the laser energy is absorbed. The amount of energy absorbed from the laser is measured to arrive at the amount of leaked medium.
Leak sniffers draw in air samples to evaluate in an analyzing unit to directly measure the concentration of the leaked medium.
Pipeline pigs are utilized for a variety of tasks in pipeline integrity management. This includes cleaning the pipelines, separating product batches, as well as gauging pipeline condition. It can help gain valuable information about corrosion, cracks, wall thickness as well as existing leaks in pipelines. In this case, we use the term smart pigging. To perform pigging, a pig is inserted into the pipeline using a pig launcher. The pig advances through the pipeline, propelled by the medium and gathers data along the way. A receiver is used to guide the pig out of the pipeline in order to subsequently analyze the collected data. Various techniques are used to collect pipeline information using smart pigs; two of the most common are the magnetic flux leakage method and the ultrasonic principle.
With the magnetic flux leakage method, a strong permanent magnet is used to magnetize the pipeline. Any changes to the wall of the pipe, such as corrosion, change the magnetic flux lines which are then recorded by sensing probes attached to the pig. Following pigging, the recorded signals are evaluated based on reference signals to detect any defects or abnormalities in the pipe wall.
When it comes to the method based on the ultrasonic principle, the pig transmits ultrasonic pulses into the pipeline wall and receives their reflected signals. The signals are reflected by both the inner and outer pipe walls and based on the running speed of the pig; the thickness of the pipe wall can be derived.
Another non-continuous solution for monitoring leaks is the use of tracking dogs. These dogs are specially trained to recognize the odour of certain compounds which are injected into the pipeline to be inspected. The pipeline is then operated as usual and the dog is led along the right of-way path, sniffing for the compound. The use of tracking dogs usually only takes place with short pipelines or segments of pipeline. It is also a good method when it is not possible to accurately localize the leak using other methods and then the dogs can be used to further narrow down the leak site. However, it is difficult to certify a tracking dog as a leak detection system within the framework of API or TRF.
Continuous Leak Detection Systems
Fibre Optic Cables
The use of fibre optic cables for the continuous external monitoring of leaks is based on physical changes that occur at the leak site. One of those physical changes is a typical change in temperature profile. To detect such changes, the fibre optic cable is placed along the pipeline. A laser then emits pulses that are reflected by molecules in the fibre optic cable. The reflected laser pulse magnitude gives insight as to the temperature at the place where the photon hits the molecule. By adding these reflections, a temperature profile can be made and it is then possible to detect the characteristic change in temperature that occurs at the leak site.
Figure 1:Fiber Optic Leak Detection
Acoustic sensors are installed outside of the pipeline to detect leaks by measuring the noise levels at multiple sites along the pipeline. This information is used to create a noise profile of the pipeline. Deviations from the baseline noise profile that is created results in the leak alarm. Acoustic sensors can be mounted directly to the pipeline or coupled to the pipe wall using steel rods for underground pipelines. To monitor longer pipelines, a large number of acoustic sensors are needed. Small leaks whose acoustic signal is small and only differ slightly from the background noise cannot be detected as otherwise there would be many false alarms.
Figure 2:Acoustic Leak Detection
When using sensor hoses, a semi-permeable hose is installed along the pipeline. In the event of a leak, the medium comes out of the pipeline and into the hose. In a timed cycle, a test gas is injected into the hose at the beginning of the pipeline. Then the contents of the hose are pumped to the end of the pipeline. There is an analysing unit at the end which then tests the hose contents for the presence of hydrocarbons. The run time of the test gas injected at the inlet indicates the total run time of the pipeline. As the total run time is known, the difference between the arrival of the medium out of the pipeline and that of the test gas can be used to derive the leak site. Due to the material-specific properties of the hose, the use of sensor hoses usually only takes place in short pipelines. The analysing units can detect very small volumes of substances meaning even the smallest of leaks can be detected. Just as with fibre optic cables, when installing the sensor hoses pay attention to the positioning of the hoses above or below the pipeline.
Figure 3:Sensor Hose Leak Detection
Mass/Volume balance method
Another type of internal leak detection system is based on Antoine Lavoisier’s conservation of mass principle. According to this principle, mass in a closed system remains constant and is not changed by processes within the system. If the pipeline is considered to be a closed system and you compare the mass flow at the inlet and the outlet, the difference in a leak-free case should always equal zero. If, however, a leak occurs, the system has been opened and mass escapes. This results in a decrease in the measured mass flow at the outlet and an increase in the mass flow at the inlet.
Figure 4:Mass/Volume Balance
Statistical leak detection systems subject a previously determined variable to a statistical test. Common statistical variables include pressure change over time and the result of a mass balancing. The so-called hypothesis test is widely used here. With this test, two hypotheses are prepared, namely:
a) Hypothesis H0: No leak
b) Hypothesis H1: Leak
The system checks whether there is enough data for the statistical variable to be a plausible part of the leak hypothesis and if it is, sends out an alarm.
Figure 5:Statistical Analysis
Real Time Transient Model or RTTM systems can compensate for dynamic changes. To do this, they make use of basic physical laws which the pipeline must obey:
The conservation of mass principle, which includes the density ρ, the time t, the flow velocity and the pipeline location coordinates
The conservation of momentum principle, which includes the flow velocity v, the time t, the pressure P, the pipeline location coordinates s, and the pipeline friction fs
The conservation of energy principle, which includes the enthalpy h, the time t, the density ρ, the pressure P, and the specific loss performance L
These physical principles precisely describe the stationary and transient behaviour of the flow in the pipeline. Using these equations flow, pressure, temperature and density can be calculated and integrated in real time for each point along the pipeline. These trends are also known as hydraulic profiles and accurately predict the true performance along the entire pipeline.
Figure 6:Real Time Transient Model
5.3 LEAK LOCALIZATION
When leaks occur in pipelines, it is not enough to know that a leak has occurred; you must also know where it is located. There are several methods that can be used to localize the leak. Internal leak detection systems include:
Gradient Intersection Method
Wave Propagation Method
Extended Wave Propagation Method
Gradient Intersection Method
The Gradient Intersection Method uses the pressure profile along the pipeline to localize the leak. Ideally, the pressure drop is linear (in a horizontal pipeline without elevation changes). If a leak occurs, the flow before the leak site increases and decreases after. This results in an increase in the pressure drop before the leak and decreases after the leak, whereby we obtain two lines with different slopes for the pressure profile. If you then follow the lines to the intersection, the leak site can be determined. The advantages of this method are that spontaneous and creeping leaks can be localized and that the accuracy is good in stationary operation. One weakness of this method is that the accuracy depends on the total length of the pipeline and that localizing accuracy is not good in transient operation. In addition, with non-model-based systems you must take into account any changes in the height, cross-section and pipe friction along the pipeline because the pressure drop is then nonlinear due to these physical attributes of the pipeline and not from a leak.
Figure 7:Gradient Intersect Method
Wave Propagation Method
The Wave Propagation Method uses the sound velocity of the medium in the pipeline. Spontaneously occurring leaks create a negative pressure wave which propagates in both directions of the pipeline at the speed of sound. Pressure gauges at the inlet and outlet record these pressure waves and we obtain the point in time at which the pressure wave reached the sensors.
The differential time of arrival of the pressure wave can now be obtained from these points in time. If the pressure wave arrives at both sensors at the same time that would mean that the leak was in the middle of the pipeline as the wave propagates in both directions at the speed of sound of the media, and if we assume a uniform density travels at the same speed in both directions. The Wave Propagation Method boasts good accuracy during stationary and transient operation as long as operational pressure waves are compensated for. The method can be used during pumping and during pauses in pumping. Creeping leaks and spontaneous leaks that are not large enough cannot be detected with this method as the negative pressure wave in these cases are not large enough. In addition, the pressure gauges must sample quickly in order to measure the point in time of the pressure wave as accurately as possible.
Figure 8:Wave Propagation Method
Extended Wave Propagation Method
To attain better accuracy the Wave Propagation Method can be expanded by adding more pressure gauges. Now when a leak occurs, we obtain additional points in time at which the pressure wave reaches the sensors. By now taking into account the sensor sampling time and the actual fluid density / sound velocity profile the exact point in time at which the pressure wave reached the sensors can be narrowed down even further.
Figure 9:Expanded Wave Propagation
At any given time, it is interesting to know what product is flowing through the pipeline. Batch tracking can be performed using the leak detection system. In this case, the positions of the products and mixing zones within the pipeline are tracked. Batch scheduling allows arrival times and capacities to be planned. Deliveries to individual tanks and buyers can also be scheduled. It is also possible to reduce the waste created by the mixing of products in the pipeline.
Figure 10:Multi-Product Batch Tracking
Pipeline pigs (pipeline scrapers) are a type of tool utilized in the pipeline industry in order to complete certain tasks including pipeline cleaning and inspection. Pigs have been used in the pipeline industry for more than 80 years with the first pigs being constructed from wood and straw with barbed wire or wire wrapped tightly around. These pigs were propelled down a pipeline in order to perform a cleaning/scraping action inside the pipeline. As the pig travelled through the pipeline, the wire scraping the inside of the pipeline caused a squeaking sound similar to the squealing of a pig, hence the term “pig” (Menon, 2011).
6.2 Common Pig Operations/Types
Pigs are commonly used for (PetroWiki, 2015):
Hydrostatic Testing – The pig allows the line to be filled with water or hydrostatic testing medium without entrapping air. The pig is inserted at the front with water being pumped behind the pig, keeping the pipe full of water. The pig forces air out of the pipeline at the front.
Pipeline Cleanup – Pipeline scraping/cleaning is done regularly in order to remove scale, wax buildup, and other types of debris from the inner wall of a pipeline in order to keep up a high pipeline flow efficiency. Natural gas pipeline pigs are used to remove trapped liquid accumulation and generally serve to keep the pipeline free of any liquid. Entrained liquid causes higher rates of erosion in a natural gas pipeline and should therefore be minimized.
Batch Transportation – Pigs are used to separate batches of different products inside of a pipeline. This is required in the case of a multi-products pipeline transporting more than one type of hydrocarbon in batches.
Prevention of Solid Accumulation and Corrosion – This is for crude oil lines in order to keep water and solids from accumulating in low spots and creating corrosion cells. This becomes particularly relevant for low velocity lines.
Internal Pipe Coatings – Pigs are used to apply certain internal coatings like epoxy-based coatings.
Inspection – One of the most frequent uses of pigs is as an inspection tool. Sizing or gauging pigs are often run after the completion of a new pipeline in order to determine if there are any internal obstructions, bends, or buckles in the pipeline. Pigs can be fitted with cameras for internal viewing of the pipeline.
Intelligent Pigs – Smart/Intelligent pigs use magnetic and ultrasonic systems in order to locate internal and external irregularities; whether those are pittings, dents, buckles, corrosion pitting, or any other abnormality.
6.3 Operation of Pigs
Pipeline pigging is achieved by inserting a pig into a pig launcher. The launcher is a type of housing connected to the pipeline, able to accommodate a pig. The launcher hatch is then closed and the valves are operated in order to create the adequate pressure and flow to release the pig from the launcher. The pig is then sent through the entire line/selected section up until the pig reaches the pig receiver/trap, which is used to trap the pig. The valves are once again operated in such a manner that the pig is received in the receiver without disrupting the flow significantly. The flow will then bypass the barrel and return to the mainline. The receiver will operate in this way until operators come and close the necessary valves to remove the pig. (Menon, 2011)
Coding and standard requirements specify that the receiver is fitted with a pressure-relief device, able to safely remove the pressure from the barrel, before the insertion or removal of a pig. The necessary pressure gauges should also be installed, in order for the safe operation of the barrel. The receiver will be able to catch and hold a number of pigs before an operator comes, drains the barrel, and cleans the pigs.
Piggable pipeline launching/receiving stations should be spaced at reasonable distances from one-another, typically between 50 and 70 miles apart. The pipeline should furthermore be designed with long radius shop bends and the use of barred tees. This eliminates the possibility of catching a pig at a lateral in the pipeline. The long radius bends should have a radius of minimum three times that of the mainline pipe diameter. (PetroWiki, 2015)
All mainline valves must be open-port design and should be designed according to API-6D. (Menon, 2011). Hot taps greater than 6 inches in diameter should also be barred. A general representation of a pig launcher and receiver dual station is shown in Figure 1.
Figure 1: Pig Launcher/Receiver Dual Station with Associated Piping (Menon, 2011)
6.4 Operational Video
The following video prepared by T.D. Williamson is an accurate representation regarding the operational procedure of a pig launcher and receiver. (T.D. Williamson, 2010)
Utility pigs can be divided into the following three types of pigs (Inline, 2017):
Foam Pipeline Pigs – these pigs are used to remove debris and water from pipelines. Foam pigs can furthermore be broken down into the following:
Bare Foam and Coated Foam Pigs – Used for general cleaning, batching and proving of pipelines. These types of pigs are generally used post construction due to their flexibility.
Brush Pigs – These pigs are fitted with brushes that remove material and debris from pipelines. These materials typically include corrosion deposits.
Foam Disc Pigs – These pigs are used for the removal liquids from a pipeline.
Mandrel Pigs – Pigs that are designed with a metal body. These pigs are customizable with the possibility of alternating various types of discs, cups, scrapers, brushes or gauging plates. Cups and discs are added where a tighter seal is required and are very effective with the removal of liquids and black powder.
Urethane Pigs – A more flexible type of pig used for wax removal or liquid displacement and is constructed as a single piece of equipment. Polyurethane is a wear resistant formulation of urethane pigs.
6.6 Pig Propulsion
A pig is propelled through a pipeline by the application of differential pressure. The amount of differential pressure required is based on the amount of frictional force exerted on the pig by the inside of the pipeline. Should the internal diameter of the line change the amount of pressure via friction applied to the pig will change (i.e. with the decrease in diameter the frictional force on the pig will increase). The pig will be held at the restriction until the pressure build-up is significant enough to propel the pig forwards. Once the pig is released from the restriction, its velocity will increase significantly and it will lose its seal on the inner surface to a certain extent. This in turn will decrease the efficiency of the pig and some debris or liquid might be left behind in the pipeline.
Low pressure gas pipelines tend to be more problematic. Once the pig stops inside the pipeline due to a reduction in pipeline diameter, the pressure can build up to double that of the normal pressure. Should this occur at the end of a pipeline and there is little resistance at the end of the pipeline once the pig is released, the pig can reach extremely high speeds (161 km/h) causing major safety hazards. (Menon, 2011)
6.7 Pig Trains
Pig trains are another form of pigging and is used for many pipeline operations and maintenance procedures. A pigging train consists of a train of pigs sent in a sequence in order to achieve a certain cleaning service. An example of this entails the use of four pigs in a train used to clean salt water from a line:
The first pig pushes a slug of clean water to eliminate/push out the saltwater
The second pig is pushing another batch of clean water
The third pig is pushing a glycol solution slug (the glycol is dehydrating the line)
The last pig is propelled by nitrogen and is pushing another slug of glycol
6.8 Intelligent/Smart Pigs
Intelligent or smart pigs are internal inspection devices (in-line inspection, ILI) used extensively for inspecting pipelines that are in service. The intelligent pig is a sophisticated form of measuring device that travels through the pipeline in the same manner as a normal cleaning pig while measuring and recording irregularities in the pipe wall that may represent corrosion, gouges, and other typical pipeline deformations, know as pipe anomalies.
Intelligent pigs can be broken down into four main types discussed in further detail below. These include the following (Menon, 2011):
Magnetic Flux Leakage Pigs
Ultrasonic Testing Pigs
Shear Wave Ultrasonic Pigs
6.9 Magnetic Flux Leakage Pig
One of the most popular types of intelligent pigs is the Magnetic Flux Leakage (MFL) pig. This pig is used in order to identify and measure possible metal loss due to corrosion, gouges etc. in the pipeline wall by the use of a temporarily applied magnetic field. The pig travels through the pipeline and induces a magnetic flux between the onboard north and south magnetic poles.
A pipeline wall with zero defects will distribute and produce a uniform and homogeneous distribution of flux. Anomalies in the pipeline wall causes a non-uniform distribution in flux. This flux distribution leaks out of the wall. Sensors on board the pig then measure these flux leakages, stores the data onboard and will later be analysed once the pig is removed from the pipeline.
The primary use of an MFL pig is to identify corrosive defects and to indicate a size for the aforementioned defect. The MFL pig has limited crack detection capabilities; though these pigs are able to detect cracks along the girth welds of the pipeline, they are unable to determine longitudinal cracks.
6.10 Ultrasonic Testing Pig
The second type of intelligent pigs are Ultrasonic Testing (UT) pigs. These types of pigs are fitted with transducers that emit an ultrasonic signal perpendicular to the pipeline surface. The signal causes an echo from the internal and external surfaces of the pipe. The signals that are received are compared to the speed of sound in the pipe and the wall thickness can then be calculated.
Cleanliness in terms of corrosion and wax build-up is therefore very important in order to successfully complete an UT test. The cleaning is especially important in pipeline with crude and heavy oils where paraffin build-up tends to occur.
6.11 Shear Wave Ultrasonic Pig
A Shear Wave Ultrasonic Pig is a modified version of the UT pig. This type of pig is designed to identify longitudinal cracks in suspended pipelines, longitudinal ERW weld defects, and crack defects. These pigs play an integral part in inspection as the cracks that occur longitudinally tend to be the most dangerous. This is due to the fact that the pipe’s hoop stress works directly on the longitudinal cracks – should these defects not be detected in time the defects will cause the rupture of the pipeline.
These pigs are furthermore referred to as a liquid-coupled tool. The pig is operated by using shear waves that are generated due to the angular transmission of the UT pulses through a liquid coupling medium.
6.12 Geometry Pig
The final type of intelligent pigs are geometry pigs or also referred to as caliper pigs. These pigs use a mechanical arm or alternatively an electromagnetic arm to measure the inner bore of a pipe. While being transported through a pipeline, the pig uses the arm attachment to identify ovality changes, dents, and deformations. These pigs can sometimes detect changes in girth weld size or even detect debris build-up in some cases.
6.13 Intelligent Pigging Preparations
Preparations in the pipeline must be completed prior to the undertaking a smart pig run, to accommodate the intelligent pig during its operation. These pigs are usually longer than normal pigs and the launchers/receivers should be able to hold the intelligent pig (Menon, 2011).
The pipeline should be cleaned prior to the launch of smart pigs. Scraper pigs should be run until the amount of debris, scale, wax or dirt is less than 23 kg per run.
A detailed pigging log should be kept. Containing information such as launching/receiving times, conditions, flow rate etc.
Steel mandrel pigs should be used in the second phase of the cleaning.
Another run with brushes attached to the pigs is also recommended.
A final run with something like a bidirectional pig with a urethane disk and spider nose assembly should be done.
A gauging plate attached to a pig should then be used in order to determine the roundness. If the gauging plate is undamaged after this run the pipeline is ready for intelligent pigging.
PetroWiki. (2015, 06 3). Pipeline pigging. Retrieved from PetroWiki: https://petrowiki.org/Pipeline_pigging
Menon, E. (2011). Pipeline Planning and Construction Field Manual. Massachusetts: Gulf, Elsevier.
T.D. Williamson. (2010, 03 27). Pipeline Launcher and Receiver Animation. Retrieved from YouTube: https://www.youtube.com/watch?v=CDHtL-J1Xxo
inline. (2017). Types of Pipeline Pigs. Retrieved from inline: https://www.inlineservices.com/pipeline-pig-types-applications/
Batches are often referred to as slugs and refer to a batch of a specific product being transported in a pipeline. Often a pipeline is utilized for the transport of more than one product (i.e. a multi-product pipeline). The hydrocarbons are therefore transported in batches in order to minimize mixing of the different types of hydrocarbons.
Batching can furthermore be utilized in cases where fuels are received from more than one source and are transported to more than one destination or have multiple intermediate take-off points. The logistics behind these operations can be quite complex and difficult to manage without the proper planning and the necessary operational philosophies and plans in place. It is therefore important to establish a batching schedule with regards to the various products being transported while considering the following key influences:
In order to compile and complete the batching schedule of a pipeline it is important to follow certain steps required to sort out the logistics of the pipeline operation. It is necessary to complete the requisite calculations regarding pipeline size, flow rates, fuel production, and fuel consumption in areas of concern. It is therefore imperative to have all the relevant market information with regards to supply and demand. The following steps should be followed as a baseline in order to sort out the logistical operation of the pipeline.
Consider the possible sources and the destinations from/to which fuel will be transported. This is important in order to know whether fuel demands can be met, but also to establish the base timeline for when a certain facility requires certain types of fuel. An easy approach for a first iteration is to break down a facility’s consumption or estimated consumption into an average consumption per week.
By then using the pipeline flow rate and possible supply of fuel it is possible to determine the duration of transport, to the facilities, for the various fuels, and the consumption requirements for each facility. This will be used to determine whether facilities receive product before the facility runs out of the aforementioned product.
Consider the depots to where fuel will be sent and analyze the availability with regards to tank storage capacity. This will be one of the base factors to determine whether the operation of the pipeline is logistically possible. Should the tank farms not be able to meet their projected demands, additional tank construction will have to be considered.
The amount of fuel anticipated to be sent to the facilities should be quantified and it should be then be determined if the tank farms have available capacity to receive the incoming product in one tank while distributing fuel from another. You therefore require enough tank storage for twice the weekly/monthly consumption in two or more separate tanks.
Once the tank availability has been addressed it is possible to decide between a batching process via pigging or via interfacing. The tank farms require enough free capacity in order to utilize some of the storage for interfacing, should the decision be made for interfacing while pig launchers/receivers will have to be installed in order to use pigs for the batching.
Once all of the above-mentioned have been considered and estimated the batching schedule can be developed by a Trial and Error Approach.
The Trial and Error Approach:
Choose a batch size for the various fuels based on possible supply and necessary consumptions at the various facilities
Schedule the batches on a timeline-based program like MS Project, with batches following each other chronologically as depicted in Fig. 2
Estimate whether the facilities receive enough fuel per specified time section in order to meet their consumption in the same time section
Estimate whether the fuel coming into the depot has at least 24 hours of “resting” prior to consumption
Calculate whether there is no product coming into a tank while being distributed i.e. don’t pump into and out of the same tank at the same time
If all of the above-mentioned points are satisfied and the batching operation of the pipeline makes sense, then the batching procedure should be successful. The thought process to be followed, in order to set up the batching for a pipeline, is shown in Fig. 1.
Figure 1: Batching Schedule Logic
The typical flow of various products in batches is shown below in Figure 2.
Figure 2: Typical Fuel Batching Procedure
The following video is a representation of how fuel batching is done as represented by Paradigm Alliance (Paradigm Alliance, 2016).
Batching procedures are typically executed by means of the following types of batching as mentioned earlier in this section:
Batching with the Use of Pigs
Batching with Interfacing
7.3.1 Pig Batching
Batching with the use of pigs requires launchers and receivers to split the batches with pigs. This is a “cleaner” alternative as the products don’t mix as much. With the use of pigs, the distribution of batches is simpler than when using an interfacing approach (as discussed later). The batching philosophy can therefore follow a simple approach where a batch of each product is sent in a sequence, the pipeline has a buffer period and the sequence is then repeated.
The line should be piggable in terms of bend radiuses, barred tees etc., and have the necessary receiving/ launching facilities in use (or constructed for a newly designed pipeline).
7.3.2 Interface Batching
Interface batching includes interfacing between batches and therefore a repetitive sequence of diesel fuel is typically utilized. The diesel fuel has the highest density but is also less sensitive to minor contamination of other hydrocarbons.
The sequence followed is therefore to transport a batch of diesel between each other type of hydrocarbon. Furthermore, interfacing requires available tank capacity for interfacing tanks. The interfacing tanks are used to store the portion of fuel that is mixed and is then usually either mixed back into a diesel tank in selected quantities or sent back to a refinery. The interface detection is done by measuring the density of the incoming fuel and switching between the respective diesel, other hydrocarbons, and interface tanks.
The following diagram is an indication of a typical schedule for interface batching.
Figure 3: Batching Schedule Representation of Interface Batching
Paradigm Alliance. (2016, 12 14). Batching. Retrieved from YouTube: https://www.youtube.com/watch?v=Lbqepa2lE3w
Multiple hydrocarbon products such as diesel, kerosene, and gasoline, are often transported in a single pipeline as this is usually more cost effective compared to using separate pipelines for each product. The different hydrocarbons can be separated with or without the use of physical separations, meaning with or without the use of pigs (or liquid plugs). In the absence of pigs, an interface forms between two adjacent products (batches), resulting in mixing, and ultimately contamination of the adjacent products. The length of this interface needs to be kept to a minimum to reduce the amount of contaminated product.
8.1 Factors to Consider
Different hydrocarbon products are consecutively transported in batches in a pipeline. To reduce contamination between two adjacent products, the length of the interface and various factors have to be considered. These factors include:
Velocity – interface volume growth decreases with increased flow rate.
Density Difference – smaller density difference results in shorter interface.
Viscosity – smaller difference in viscosity results in smaller interface volume.
An increase in batch size does not affect the amount of interface product but can reduce the amount of reprocessing or refining required, thereby reducing the associated costs. Contrarily, the order in which batches are transported has a significant effect on the amount of refining that is required. It is important to keep the following in mind:
Immiscible products shouldn’t be placed adjacently
Products with notable differences in viscosity shouldn’t be placed next to each other
Interfaces are developed at early stages in transportation. Therefore, after an interface has been established, products moving through pump stations further along the pipeline do not significantly change the amount of contamination.
8.2 Interface Sizing
Densitometers, measuring the specific gravity of the product in the pipeline, are generally used to detect transitions between products and interfaces. Sound-velocity interface detectors or continuous colorimeters (detecting changes in products’ colour) can alternatively be used. More accurate detection of interfacial changes leads to a decrease in product contamination.
The length and volume of interfaces can be calculated by considering various factors, such as the two adjacent products’ densities, viscosities and the velocity of the fluids. As it is difficult to determine the exact concentration of each product in the interface, it is usually assumed that equal amounts of both products are present in the interface mixture. The density of the mixture and kinematic viscosity is calculated by:
Density of Mixture (ρ):
Kinematic Viscosity of Mixture (ѵ):
These values are used to calculate the dimensionless Reynolds number of the interface:
where v and D is the velocity and pipe diameter, respectively.
The Reynolds number is used to calculate the friction factor with Serghide’s method:
Austin & Palfrey’s method is most commonly used to determine the length of the interface.
Thereafter, the interface volume can simply be calculated as:
8.3 What to do with the Interface
Formed interfaces must be removed to avoid degradation beyond the maximum allowable contamination of the products. After the interfaces have been removed, they must be reprocessed to deliver saleable products. It is however, more economically appealing to blend the interface into one of the adjacent products, by adding it to one of the products’ tanks. In this case, it is important to ensure the product specifications are still met, otherwise the product will be downgraded.
Further separation is typically done by arranging products in ascending or descending order of product quality or density. The correct batching sequence can reduce the interface volume and thus the amount of contamination. As the requirements – with regards to fuel specifications- in Africa aren’t that restricting yet, the interface mixture is usually added to the diesel tank. (In Africa) Diesel is commonly used as separating product between other hydrocarbon products. In countries where the contamination criteria is more stringent, the use of pigs will become necessary to ensure that for example, the kerosene (with a high sulphur content) doesn’t contaminate the diesel (lower sulphur content).
8.4 Interface Processing
Interfaces typically represent 5-10% of batches. The interface that must be diverted to a separate tank is referred to as transmix, it is diverted to avoid contamination of the adjacent batches. These interfaces and transmixes no longer adhere to the required specifications and standards but cannot simply be discarded as it will lead to a great loss in profit.
8.4.1 Transmix reprocessing
The transmix has to be reprocessed or refined to produce a marketable product. This can be done by either shipping the transmix of to a refinery or constructing a refinery at the terminal. At the refinery the transmix goes through a distillation process, separating the different products. Increasing batch sizes can minimize the amount of product reprocessing required. The volume of product in a pipeline, however, is still dependent on tank sizes, customer demand, and schedule requirements.
Interfaces between common products can be mixed or “cut” into the lower quality product. The lower quality product is thus further downgraded by the addition of the interface.
Blending is the process of mixing intermediate hydrocarbon products and additives to produce a final, marketable product that adheres to required specifications and environmental standards. It is more profitable to maximize the blending of the higher value product, up to the specification limits are met. The three most common methods of blending are:
In-line Blending – turbulence ensures extensive mixing when proportionate amounts of each component is added directly to the main stream in a pipeline.
Batch Blending – additives are added during or/and before blending. Additives such as anti-oxidants or octane enhancers can provide certain properties, not inherent in the hydrocarbons.
Onboard Blending – products can be prepared to specification without the use of onshore facilities.
Online blending (and in-line), ensuring enhanced accuracy, has become more common due to technological advancements, computerization, and the accessibility of certain equipment. Many different software packages that optimize the blending process and production of profitable products are available.
Pipeline companies install a series of components and equipment to ensure that the pipeline systems operate in an efficient, reliable, and safe manner. Valves are essential parts of any piping system used to obtained the aforementioned operating objectives by controlling the flow and pressure of fluids.
There are many reasons why a pipeline may need to restrict gas flow in certain areas, including emergency shutdown (safeguarding people and protect property) and maintenance. For example, if a section of pipe requires replacement or maintenance, valves on either end of that section of pipe can be closed to allow engineers and work crews safe access.
When valves are located correctly, properly maintained, and correctly operated, it can reduce the volume of product released in the event of a pipeline failure. Valves serve to block or isolate pipeline sections for required maintenance or emergency situations.
However, valves can increase system complexity and have inherent risks. The installation of a valve can have an environmental impact and the valve itself can have issues related to reliability, leakage, and susceptibility to accidental damage or vandalism. It is essential to assess and analyse the engineering and environmental impacts of valves holistically, in the context of the entire pipeline system and surrounding landscape. The risks could outweigh the benefits, if a valve is placed in a sensitive environment.
Although a number of valves are in operation at each pumping station, the critical valves (also generally referred to as mainline block valves) in a pipeline are spaced every few kilometers along the pipeline systems. All mainline valves such as block valves are either operated manually, remotely or automatically:
Manual Valve: Opened and closed by pipeline personnel on-site.
Remote Valve: Opened and closed remotely from a pipeline flow control room.
Automatic Shut-off Valve: Shut-off valves close automatically if pipeline pressure drops or if flow direction changes. As an additional safety measure, automatic valves also can be closed manually.
The minimum required spacing of these valves is prescribed in ASME B31.8, ‘Pipeline Transportation Systems for Liquid Hydrocarbons & Other Liquids.’ Liquid pipelines have the following criteria for valve placement.
Valves are placed:
At the suction end and discharge ends of a pump station
On each line entering or leaving a storage tank area
On each mainline at locations along the pipeline that will limit damage or pollution from accidental hazardous liquid discharge
On each lateral take-off from the trunk line
On each side of a water crossing that is more than 30 m (100 ft) wide
On each side of a reservoir holding water for human consumption
Additionally, check valves may be installed on grades and the downstream side of rivers and streams for more protection from backflow conditions in case of a line breach.
Most block valve installations are outfitted with automatic shutdown controls. These controls are set to close the valve if pressure or flow rates change, indicating a possible breach in the line. By having these valves spread out throughout the pipeline, the amount of potential fluid leakage that might occur during a pipeline break is limited. Furthermore, many pipeline valves are designated as emergency shutdown valves (ESD), which are remotely operated from the pipeline control room.
Figure: Valve site for a variety of aboveground valves to control fluids in pipeline
Valves sites are roughly 45m x 30 m (150 ft x 100 ft) in area and typically remain within the pipeline right-of-way (ROW) corridor. All vale sites are designed and built to meet or exceed provincial and national safety regulations, environmental and emission requirements and fire safety codes. All valve sites locations appear as a small fenced area (locked entry) within a cleared ROW unless the site is in an open field.
The use of pipeline transportation is the most economical and reliable method available when transporting large amounts of liquids and gaseous commodities. However, when transporting products of different physical properties such as petrol, diesel, and Jet A1 in the same pipeline, the situation becomes more intricate due to the complicated pressure characteristics along the pipeline.
Multi-product pipelines can be operated in two modes, these are either the Fungible or the Segregated mode. Segregated products are blend-stock or branded commodities. The identity of segregated products is maintained throughout the piping process, the same commodity order that is received for shipment will be delivered to the shipment destination. On the other hand, Fungible commodity batches consist of generic products that meet required specifications. Fungible commodities will be received as equivalent products that match the set-out specifications but will not necessarily be the original lot shipped at the specified input terminal.
10.1 Pumping System Principles
10.1.1 Flow Head
Head is a main influencing factor on the pump selection process and depends on the following factors:
The sum of pressure drops caused by pipe friction resistance, losses due to bends and the resistance of other fittings.
The pressure difference between pipe inlets and outlets caused by elevation differences.
The predetermined flow head required.
10.1.2 Net Positive Suction Head (NPSH)
NPSH is an international dimension used to calculate the supply conditions. Fundamentally, in all pumps the static pressure in the suction socket must be above the vapour pressure of the commodity to be pumped. The NPSH of a pump is determined by measurements taken at the delivery side of the pump. It needs to be ensured that the NPSH available in the system is larger than the NPSH required to avoid cavitation. This NPSH required (NPSHR) can be read off a pump curve.
Cavitation in pumps occurs when bubbles or cavities in the liquid develop in low pressure areas around the impeller. When these bubbles or cavities collapse they cause shockwaves inside the pump which can erode the impeller and other pump components after time. Cavitation can be prevented through:
If possible lowering the temperature of the commodity being pumped.
Increasing either the static suction head or the supply pressure.
Reducing the pressure drop (caused by losses in the pipe) in the suction pipe by:
Choosing a larger size diameter suction pipe or
Shortening the length of the suction pipe or
Lessing the amount of bends or valves in the pipeline or
Changing the roughness profile on the inside of the pipe, for example HDPE has a much lower friction factor than Carbon Steel
Adding a DRA (Drag Reducing Agent)
10.1.4 Pressure Drops
Pressure Drops again are an essential factor in pipe system design and pump selection.
Pressure Drops can be caused by losses due to:
Friction of pipes in the pumping system
Piping Components such as valves, bends, inlet and outlet shapes
Other possible process units such as heat exchangers
10.2 Reading a Pump Curve
The basic principle behind any pumping system is to move various commodities from one location to another. All pumping systems have flow and head characteristics. The amount of pressure the system needs to overcome to produce the required head, determines where the system will operate on a pump curve.
As pressure increases in a pipeline, the flow through that pipeline will decrease and the performance point on the pump curve will move to the left. As pressure decreases, flow increases, and the performance point on the pump curve moves to the right.
Each pump curve has a solid line which indicates the minimum allowable flow through that pump. This flow is required to dissipate heat created in the pump. Operation to the left of this line will reduce pump life and is not recommended. Therefore, sizing a pump correctly is integral to maintaining a healthy pump system. Minimum flow rate is indicated by the red line in the figure below.
The Best Efficiency Point (BEP) is defined as the flow at which the pump operates at its optimum efficiency for a given impeller diameter. The key to consistent pump performance is to find the BEP of the pump. Operating near the BEP also leads to financial benefits as a more efficient pump use leads to less electricity use and longer pump life. The BEP is found on the pump curve at the intersection between required flow rate and the required head.
There are three efficiency categories used to describe hydraulic pumps:
Volumetric efficiency is determined by the division of the actual delivered flow by the theoretical flow. Actual flow is measured using a flow meter and the theoretical flow is mathematically calculated.
Mechanical efficiency is determined by the division of the pump’s theoretical torque required to drive it, by the actual torque required to drive it.
Overall efficiency is simply the product of volumetric efficiency and mechanical efficiency. This entity is used to describe the drive power required by a pump at a given flow and pressure.
First, identification of flow rate is required. Flow rate in all three curves show above is located on the horizontal axis and its unit is cubic metres per hour (m3/h). Secondly, we need to determine what head the pump needs to overcome. Head is located on the vertical axis in the top graph above and its unit is in meters (m).
We now need to draw a line vertically upward from the horizontal axis at the required flow rate. We also need to draw a horizontal line straight from the vertical curve at the required head. Where these two lines intersect, we find the performance point of the pump.
The second graph above indicates Net Positive Suction Head Required (NPSHR). The NPSHR can be read off the graph at the intersection between the NPSHR curve and a vertical line drawn upward from the required flow rate on the horizontal curve.
Lastly, the third curve shown above indicates the required pump power. The pump power can be read off the graph at the intersection between the power curve and a vertical line drawn upward from the required flow rate on the horizontal curve.
Once all the above-mentioned entities have been calculated a suitable pump can be selected.
10.3 Overview of Multi-Product Pipeline
The greatest feature of a multi-product pipeline is batch transportation. The term ‘batching’ refers to the process in which different commodities are sent through the same pipeline is a series of batches. For example, operators will pump diesel for several hours before switching over to the next batch and then pumping petrol for the next few hours. The process of tracking and managing these batches is done through scheduling. Scheduling multi-product pipelines consists of two main activities – input and delivery.
The input step of scheduling consists of a sequence of batch injections. Before a batch can enter the pipeline the batch size, pump rate and input terminal need to be determined. A very important step in the input phase is to determine the input sequence of the commodities. The reason for this is to reduce interface costs, by avoiding product mixing or the need for pipeline cleaning. As different commodities will be pumped through the same pipeline, certain sequences of commodities need to be avoided to prevent the contamination of specific commodities with the product that was pumped previously.
Approaches to studying problems pertaining to pipeline scheduling include optimization models, knowledge-based techniques, and decomposition frameworks. Mathematical approaches to studying these problems are divided into a discrete class and a continuous class depending on how the product route is handled and the time domain which it falls within.
Firstly, discrete formulation consists of dividing the pipeline volume into various single-product regions and then dividing the planning horizons into various time intervals. Most commonly time and volume are divided uniformly, however alternative approaches are available. More accurately some formulations have put forth the idea that pipeline segments can be divided into either equal or different prescribed volumes. This approach considers changes in the pipeline diameter. In terms of time this second approach allows for time intervals of adjustable duration to consider changes in the pump injection rate as well.
Alternatively, in the case of continuous class approaches, the optimisation methods do not consist of any decomposition. These methods calculate the optimal input schedule from a single refinery through minimization of the sum of pumping, interface and inventory cost.
Variable Speed Drive (VSD) adjustments are not appropriate for all pumping systems. When used in systems with high static head, slowing down the pumping speed risks inducing vibrations and creating performance problems. In systems where the static head represents a sufficient portion if the total head, caution needs to be taken when deciding on whether to use a VSD. In other cases, a VSD pumping system is simply not necessary.
VSD systems in pumping is a valuable application when it comes to a single pump with multiple head duty points. In a situation where a pump has a relatively constant flow but a varying head due to the land topography, VSD allows for a change in the pressure of the pump by changing the rotational speed of the pump impeller. This process can generate considerable energy savings.
Another major advantage associated with VSD is the ability to control the start-up and stopping frequency of the pump. This not only increases the pump lifespan, but also saves cost due to energy use reduction. When motors are started it can take up to 7 times the motor full-load current to get the motor started. This process generates heat and contributes to shortening the life of the motor. When using a VSD pump the pump is started at zero frequency and voltage and as the two “build” it “magnetizes” the motor windings which takes between 50%-70% of the motor full-load current. This is a major contributor to the total energy savings associated with a VSD.
When it comes to multiproduct pipelines VSD is sometimes used to regulate pressure characteristics along the pipeline. Different commodities will have different physical properties, and thus to maintain specified pressures and flow rates in the pipeline, the speed at which the commodities are pumped needs to be adjusted accordingly.
If the different commodities in a multi-product pipeline can all be pumped at the same impeller speed, without exceeding the allowable pressure or required flow rates, a VSD is not required. With an increase in commodity density, the pressure in the pipeline will increase and therefore the velocity will decrease. If this velocity however is not below the settling velocity and the pressure doesn’t exceed the allowable pipeline pressure, no VSD is needed and batching and scheduling will become very important tools.
A VSD regulates the speed and torque output of the pump. This process is made possible by changing the frequency of the pump supply voltage to allow continuous process speed control. The VSD also has a pressure sensor to detect down-stream pressure and adjust the pump speed to keep the measured pressure at the required value.
In summary some of the potential benefits and drawbacks of VSDs are:
Improved Process Control
Improved System Reliability
Improved Power Factor
Programmable Acceleration and Deceleration
Rotor Dynamics (Lateral critical speed)
Additional Application and Design Considerations
10.5 Drag Reducing Agents (DRAs)
The use of drag reducing agents has recently become part of the piping system design process and is no longer just considered as a boost to existing pipelines. Drag reducing agents are long-chain polymers which are injected into pipelines to improve flow by reducing turbulence and thus increasing capacity.
It is important to note that DRAs are applied to pipelines with turbulent flow regimes, and are not effective in pipelines with laminar flow regimes. Commercially DRAs were first used on the Trans-Alaska Pipeline in 1979. The use of DRAs reduced drag in the pipeline by 50% and thus increased the pipeline capacity from 1.45 to 2.1 MBPD.
Essentially DRAs reduce the required pumping power and thus increase the pumping system’s capacity. This innovation means that pipeline capacity is no longer just dependent on pipeline diameter, commodity viscosity, and pump specifications. Drag Reducing Agents are used almost exclusively on transmission pipelines, which transport either hydrocarbon liquids from central collection areas to storage facilities, or transports refined products (Diesel and motor gasoline but not jet fuel) from central collection areas to storage facilities.
Some of the advantages associated with DRAs are:
Design Phase Pipe Diameter Reduction
Required Pumping Stations Reduced
Required Pump Size Reduction
Overall System Cost Reduction
Generally, it is not considered economically viable to add DRAs in oil gather systems. In event that a significant production increase is required from a multi-well pad, or a field using the existing infrastructure, DRAs are however, quite useful.
In terms of multi-product pipelines, a major advantage associated with DRAs is operational flexibility. DRAs can be implanted on a temporary basis or immediately depending on operational requirements. In terms of multi-product pipelines this gives engineers the ability to add DRAs to certain commodity batches as is required to maintain the desired pressure, flow rate or pumping schedule.
Researchers still have a long way to go regarding understanding the phenomena associated with DRA’s and heat transfer. Specific applications of DRAs require a closer look at the heat transfer process as well as the involved hydrodynamic process. It is interesting to note for example in the case of crude oil pipelines, the effects of DRAs on the heat transfer process can be useful in keeping heat loss to the atmosphere to a minimum, while keeping the oil pumping power lower. Thus, in some cases DRAs can even bring down the cost on items such as thermal insulation of the pipelines.
Drag Reducing Agent selection is dependent on the application under consideration as well as the cost. Currently Drag Reducing Agents are being used in a variety of fields such as the shipbuilding industry, fire-fighting operations, and possibly soon the medical field – which is a testament to their value.