How “Spectra Energy” Planned Pipelines and Routes

Spectra Energy Corp is one of North America’s premier natural gas infrastructure companies serving three key links in the natural gas value chain: gathering and processing, transmission and storage, and distribution.

Spectra Energy conducts extensive environmental and archeological studies as part of the pipeline design process. This includes coordination with local, state and federal agencies to identify sensitive areas, such as wetlands and historical and cultural sites. Our environmentalists walk the entire pipeline corridor to get the input of local residents so that the final pipeline route will avoid such sensitive sites.

They use the following process to determine an environmentally friendly route for the pipeline:

Map Review Level

Natural Resources, Minimize:

  • Length of crossing of large wetland complexes
  • Number of waterbody crossings
  • Length of crossing of designated wildlife habitats (Wildlife Management Areas; designated rare, endangered and threatened species habitats)

Designated Land Uses, Avoid:

  • Abandoned mines
  • Historic landmarks
  • Cemeteries
  • Documented cultural sites
  • Superfund hazardous waste sites
  • Landfills

Select Optimal Crossing Location:

  • National Forest Service land
  • Parkways
  • Parks or trails (state, town, local)
  • Residential subdivisions/mobile home communities
  • Commercial/retail areas
  • Planned highway, housing, commercial/industrial developments

Construction Considerations to Reduce Environmental Impact:

  • Avoid rock outcrops
  • Avoid severe terrain (e.g. cliffs)
  • Minimize overall length
  • Minimize side slope crossings

Routing Opportunities:

  • Existing pipeline corridors
  • Existing electric power transmission line corridors
  • Existing roads or railroads

Field Review Level

Natural Resources:

  • Plan perpendicular stream crossings
  • Maintain vegetative buffers at parallel streams

Designated Land Uses:

  • Minimize physical and aesthetic impacts on parks, trails
  • Maintain at least 50 feet between pipeline construction work areas and residences
  • Minimize impacts (visual, crossing length, etc.) to other designated land uses

Construction Considerations to Reduce Environmental Impact:

  • Minimize crossings of side slopes

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Pipeline Global Buckling

Pipelines like other slender strcutures with compressive forces, can buckle globally if the axial compresssion goes beyond a certain level. Buried pipeline normally tend to buckle in upheaval direction (upheaval buckling) and exposed pipelines normally tend to buckle laterally (lateral buckling).

In most cases, evaluations relevant to the global buckling threat will already start taking place in e.g. feasibility studies carried out during the concept phase. With regard to global buckling, the system risk review and strategy development activity should be initiated by participating in such early studies [1].


The most relevant failure modes of global buckling are as follows [1]:

  • Local buckling, which is normally the governing failure mode resulting from excessive utilization. Local buckling appears as wrinkling or as a local buckle on the compressive side of the cross section. Local buckling can lead to excessive ovalisation and reduced cross-section area. This means reduced production, or even full production stop if e.g. a pig should get stuck. A locally buckled pipeline cannot stand an increased bending moment in the pipeline. This could lead to pipeline collapse and full production stop.
  • Loss of containment, as a result of:

Fracture, is failure on the tensile side of the cross section also resulting from excessive utilization. Fracture leads to leakage or full bore rupture, meaning reduced production, or even full production stop.

Low cycle fatigue, which can occur for limited load cycles in case each cycle gives strains in the plastic region; i.e. the utilization is excessive in periods. Low cycle fatigue may lead to leakage or rupture, meaning reduced production, or full production stop.

Hydrogen induces stress cracking (HISC), can occur in martensitic steels (“13%Cr) and ferritic-austenitic steels (duplex and super-duplex). Blisters of free hydrogen can create cracks in steel or weld at a CP/anode location when the steel is exposed to seawater and stresses from the buckle. The pipeline utilization does not have to necessarily be excessive. HISC leads to leakage or full bore rupture, meaning reduced production, or full production stop.

True Stories

  • In January 2000, a 17km 16-Inch pipeline in Guanabara Bay, Brazil, suddenly buckled 4m laterally and ruptured, leading to a damaging release of about 10,000 barrels of oil, and to great embarrassment to the operator. Field observation showed that as a result of temperature increase, the pipeline displaced laterally, when failure took place. Operating pressure and temperature of the pipeline were 400bar and 95°C, respectively. The soil beneath the pipeline was very soft clay with about 2kPa undrained shear strength at seabed [2].
  • In December 2003, side-scan sonar survey of a 10km pipeline transported wet gas in South East Asia, identified six lateral buckles along the pipeline length. The original pipeline design did not consider lateral buckling as a design issue; consequently, the effect of lateral buckling on the pipeline integrity was not clear. Results of a detailed lateral buckling study showed that the pipeline should be replaced within few years. Design Methodologies

Pipeline design against lateral buckling involves three main Levels:


In this level, an analytical approach (e.g. Hobbs [4]) will be used to check if the pipeline is susceptible to lateral buckling. The results of this level answer to the following questions:

  • Is pipeline susceptible to lateral buckling?
  • Which areas of the pipeline are susceptible to lateral buckling?
  • Can we avoid lateral buckling by changing the concrete coating thickness of the pipeline?


In this level, a detailed finite element analysis will be performed on the areas of the pipeline, which found to be susceptible to lateral buckling in Level 1 analysis. The results of this level answer to a main question: are limit state conditions acceptable in areas of the pipeline with unplanned buckle?


If the answer to Level 2 question is no, this level will be commenced. In this level, a mitigation measure will be selected based on project and client requirements. The most well known mitigation methods are as follows:

  • Increasing the concrete coating thickness in selected regions of the pipeline. One example of this approach is Reshadat 16-Inch oil pipeline in Persian Gulf, the concrete weight coating thickness of the first 5km of the pipeline was increased from 45mm to 65mm.
  • Laying of the pipeline in zig-zag shape (snake lay). This method was successfully utilized in South Pars Phase 6 and 7, Jade pipeline in North Sea, Penguins flow line in North Sea
  • Laying of the pipeline on pre-installed sleepers (vertical upset method). This method was successfully utilized in PC4-B11 pipeline in Malaysia, King flow line in gulf of Mexico.

Other less popular methods such as adding either expansion spool or buoyancy modules at selected intervals, and rock dumping also may be used.


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Pipeline Stress Analysis

Why ?

The reasons one does a pipe stress analysis on a piping system are as follows

  • to comply with legislation
  • to ensure the piping is well supported and does not sag or deflect in an unsightly way under its own weight
  • to ensure that the deflections are well controlled when thermal and other loads are applied
  • to ensure that the loads and moments imposed on machinery and vessels by the thermal growth of the attached piping are not excessive
  • to ensure that the stresses in the pipework in both the cold and hot conditions are below the allowables

How ?

The piping system is modelled using analysis software such as CAESAR II, available from Chempute Software. The model is constructed from piping general arrangement drawings, piping isometric drawings and piping and valve specifications. Once the system is accurately modelled, taking care to set the boundry conditions, comprehensive stress analysis calculations are done, modifications to the model are made to ensure compliance with the above requirements.

The modifications may include one or more of the following tools


A device which prevents, resists or limits the free thermal movement of the pipe. Restraints can be either directional, rotational or a combination of both.


A rigid restraint which provides substantially full fixety, ie encastre or built-in, ideally allowing neither movements nor bending moments to pass through them.

True anchors are usually difficult to achieve. A seemingly solid gussetted bracket welded to a house column does not qualify as an anchor if the column does not have the strength to resist the loads applied to it.

Expansion Loops

A purpose designed device which absorbs thermal growth; usually used in combination with restraints and cold pulls.

Neutral Planes of Movement

This refers to the planes on the 3 axes of a turbo machine or pump from where expansion of the machine starts eg the fixed end of a turbine casing. This information is normally provided by the equipment manufacturer. If not available from this source, the fixed points of the machine must be determined by inspection and an estimation of the turbine growths calculated.

A pipe restraint positioned in line with a neutral plane prevents differential expansion forces between the pipe and the machine.

Cold Pull or Cold Spring

This is used to pre-load the piping system in the cold condition in the opposite direction to the expansion, so that the effects of expansion are reduced. Cold pull is usually 50% of the expansion of the pipe run under consideration. Cold pull has no effect on the code stress, but can be used to reduce the nozzle loads on machinery or vessels.

Spring Hangers

Used to support a piping system that is subjected to vertical thermal movements. Commercially available single coil spring units are suitable for most applications. Supplier’s catalogues adequately cover the selection of these springs. According to Hooke’s law, the spring’s supporting capacity will vary in direct proportion to the amount of displacement the spring undergoes due to thermal movement. This variation between cold and hot should be between 25 and 50% of the hot loaded condition.

Solid Vertical Support

In places where vertical thermal movement does not create undesirable effects, or where vertical movement is intentionally prevented or directed, solid supports in the form of rollers, rods or slippers are used.

It is important that free horizontal movement of the pipe is not impeded unless horizontal restraint is desired. Slipppers and rollers must be well designed and lubricated.


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What is the difference between elbow and bend in piping?

“All bends are elbows but all elbows are not bends.” 
Infact, the pipe is bent to form an elbow. 
Elbows are pre-fabricated and are firm in design. 
There are issues with bends since the tickness at the bend radius reduces as we bend the pipe. 

Sharp bends are normally called Elbows. Bends typically have a minimum bending radius of 1.5 times pipe radius (R). If this bending radius is less than 1.5R, it is called Elbow. Reference to any international / industry standard need to be traced. 1.5, 3 & 4.5 R are the most common bending radii in industry.


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Electrically heated pipe-in-pipe (EHPIP) – A qualified reelable technology to meet flow assurance challenges

Hydrate and wax plugging often limit subsea tieback distance and deepwater field development, and can make remote oil and gas resource recovery uneconomic or excessively risky.

Maintaining the produced fluids temperature outside the critical hydrate or wax formation zone often can be done using a high-performance passive insulation system such as pipe-in-pipe. However, flow assurance trends suggest that passive insulation alone does not suffice for the development of the most demanding fields or requires added flow assurance strategies involving large amount of chemical inhibitors. To address this, Technip has developed and qualified a reelable electrically heated pipe-in-pipe system (EHPIP). It combines the best available passive insulation technology at atmospheric pressure with safe and reliable electrical trace heating to optimize performance and minimizing potential opex and topside capex.

Pipe-in-pipe is an established technology for deep and ultra deepwater.1,2 It provides unrivalled passive insulation to minimize heat losses to the environment to allow development of deepwater fields with low reservoir temperature, wax or hydrate risk, or those remote from topside infrastructure.

To meet increasingly stringent flow assurance requirements, a natural extension to reelable pipe-in-pipe is the addition of active heating. Electrical trace heating, widely used onshore and for some offshore applications, can be applied to an existing reelable pipe-in-pipe system. Electrical heating allows the flowline temperature to be maintained above critical levels, to control warm up, or to extend cool down time. Thus it provides the operator a way to optimize production and reduce risks of blockage. This flexibility can be enhanced further with optical fiber technology, which already is used offshore for real-time flowline temperature profile monitoring.

General description

The EHPIP is a standard reelable pipe-in-pipe system to which Technip has added a trace heating system between the flowline wall and the thermal insulation for optimum efficiency.

The EHPIP system can be divided into three main parts:

• The pipe-in-pipe itself, comprising of standard components such as high performance insulation and structural polyamide centralizers (with slots to accommodate passage of cables) but also the trace heating system and an optical monitoring system. The electrical heat is provided by pure Joule resistive effect

• The subsea power feeding arrangement includes a power umbilical and subsea connectors. The umbilical transports electricity and optical signals from the topside to the subsea umbilical termination arrangement (SUTA). The SUTA connects to the EHPIP via flying leads, which in turn connect into wet-mate connectors mounted on tee structures. This tee piece structure provides the interface between the wet pressurized subsea environment and the dry atmospheric pressure pipe-in-pipe annular space. In the case of a field including a flexible riser, it is conceivable that the riser itself is heated and conducts both electrical power and optical fiber to the EHPIP. Technip has installed an integrated production bundle (IPB) in Angola

Schematic of electrically heated pipe-in-pipe system.

• The topside control unit together and electrical power production facility. This regulates the power supplied to the cables within the EHPIP by monitoring the temperature of the flowline using optical fibers. Topside control units for similar applications exist for IPB risers.

The trace heating system is based on a three-phase STAR configuration. This means three separate cable cores each conduct one phase of the three-phase current. Each phase meets at the star connection remote end, where the sum of current phases is nil. Consequently, there is no requirement for a return current umbilical.

The base case cable design, on Technip’s first subsea EHPIP application is constructed so the three phases (cores) of one system are housed within one outer jacket. In other words, one cable represents one individual trace heating system. Each core is sufficiently insulated to withstand the required system voltage. The entire assembly is enclosed in a braided metallic outer protective layer. This flat, compact cable geometry eases application during the assembly stage, while limiting impact on the overall heat transfer coefficient (OHTC). It also benefits from an optimum contact surface against the heated flowline to maximize heat efficiency and reduce risk of over-heating.

Due to the assembly procedure of a rigid pipeline, it is not possible to apply the trace heating cable in one continuous length. In-line connections are designed to be efficient and safe links between two sections of trace heating cable. Reeling is arguably the easiest installation technique to adapt to trace heating. Assembly and connections are made and tested onshore. Furthermore, the number of in-line connections is reduced (typically every 1 to 1.5 km [0.6 to 0.9 mi], depending on the size of the construction base).

Three-phase STAR configuration.

The trace heating system on the first-ever field application of EHPIP is designed for long-term exposure to a design temperature of 120ºC (248ºF) and a phase voltage of 2 kV. One single-cable system is can provide the required heat. As a spare philosophy, more than one cable system can be designed in to provide 100% redundancy per additional cable system. By default, more than one cable will be used conjointly during operation, hence minimizing heat output per cable. Use of a single cable for heating would occur only in the unlikely event all of the other spare cables fail. This unlikely scenario is termed as “degraded mode.”

Temperature monitor is by optical fiber. Additional layers can be placed around the fibers for mechanical protection. Optical fibers are used in a number of subsea components such as umbilicals and IPBs. Temperature monitoring is achieved either using distributed temperature sensing (DTS) or fiber Bragg Grating technology (FBG).

Spiraling machine arrangement schematic. (Located between the outer pipe stalk length and the inner pipe length pushing machine).

Both the base-case design trace heating cables and the optical fibers are applied onto the flowline in a spiral configuration to ensure compatibility with the reeling operations. This involves a spiraling machine integrated within the existing pipe-in-pipe stalk assembly process, with little disruption to fabrication. The spiraling machine arrangement is based on Technip’s experience in the manufacture of flexible pipelines and umbilicals.


A high-performance trace heating system allows an operator to minimize non-productive shut-down times by ensuring efficient warm up, by maintaining the temperature of the line above a critical wax/hydrate level, or by slowing cool down. As a result of the high performance of the passive insulation and the location of the trace heating against the flowline wall, the linear power input necessary to meet the heating requirements is relatively small compared to other systems. This minimizes topside power input or enables heating over greater distances.

The following list summarizes some of the possible applications for the EHPIP concept:

• An alternative to a pigging loop for wax or hydrate mitigation

• Very long tiebacks

• SCR heating to counter temperature drop caused by adiabatic cooling (Joule-Thompson effect). Such application also exists with IPBs

• To complement passive insulation during steady-state operation. This applies especially to heavy oil fields where high wax-appearance temperature (WAT) may force continuous heating for years. The lower opex of EHPIP, associated with both passive and active efficiency is then a significant advantage. Providing long-term continuous and uniform heating is an advantage of EHPIP

• To be used with a downhole electrical submersible pump (ESP), using an electrical subsea switch module (ESSM), to divert the pump’s power supply to pipeline heating during shut-in

• To heat short bypass sections, allowing flexibility of field operations.

The passive insulation and active heating performance of an EHPIP is generally project specific and depends on key input parameters including, but limited to target OHTC, target heating temperature, fluid properties, pipeline dimensions and length, and trace heating redundancy policy.

System qualification

A strong basis of the EHPIP design is to maximize the combination of components that have track records in comparable or harsher conditions. For example, Technip has a track record in the design manufacture and reel installation of pipe-in-pipes. Reeling of electrical cables occurs regularly with a power umbilical or IPB, and at tighter radii of curvature than experienced by EHPIP during reel-lay.

Emphasis on manufacture quality and control is equally important and is achieved through the selection of the reeling pipe-lay method. Indeed, manufacture of pipeline stalks is in factory-like environment at the local onshore base, away from the offshore construction critical path. It is possible to introduce many steps of integrity control of both the electrical trace heating and optical monitoring systems. Furthermore, as mentioned, the other advantage of reel-lay is that the manufacturing process cuts the frequency of in-line connections to one every stalk length.

A first qualification program phase was undertaken in 1999-2004. It included the following:

• Review of the full electrical design, including assessment of the electrical integrity of the system, including consideration of induction effect

• Definition of topsides power, control, and monitoring systems and philosophy

• Development and testing of cable lay up arrangement compatible with the reeling process

• Development and trial of EHPIP assembly procedures

• Specification of integrity testing requirements during assembly and installation

• Full scale 8-in. in 14-in. EHPIP joint, including all components of the trace heating system, a T-piece and power connectors was fabricated. The thermal performance, pre- and post-reeling, was established to confirm that the design calculations were accurate. For this, the test piece was submerged in a water tank at a regulated temperature of 4ºC (39ºF) and a flow loop circulated oil through the test piece.

In 2009/2010, a fasttrack qualification campaign was undertaken in partnership with a major operator to further qualify EHPIP for a long-term temperature exposure of 120ºC (248ºF) and with the option to further extend heating ranges by enabling phase voltage applications up to 2 kV. As part of this qualification, it was decided to revisit failure mode identification. A number of activities were then defined to address the issues raised during the system review process. These were packaged into the following activities:

• Preliminary EHPIP design

• Thermal analyses

• Full-scale thermal trial

• Demonstration of long-term integrity through laboratory tests

• T-piece design and assembly

• Electrical design (power feed) and components specification

• Onshore assembly procedure (including testing)

• Offshore installation procedure (including testing)

• Operability and reliability assessment

• Review of thermal monitoring

• Assessment of effect of reeling on heat tracing cables.



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Directional Boring

Directional boring, commonly called horizontal directional drilling (HDD), is a steerable trenchless method of installing underground pipes, conduits and cables in a shallow arc along a prescribed bore path by using a surface-launched drilling rig, with minimal impact on the surrounding area. Directional boring is used when trenching or excavating is not practical. It is suitable for a variety of soil conditions and jobs including road, landscape and river crossings. Installation lengths up to 2000 m have been completed, and diameters up to 1200 mm have been installed in shorter runs. Pipes can be made of materials such as PVC, polyethylene, polypropylene, Ductile iron, and steel if the pipes can be pulled through the drilled hole. Directional boring is not practical if there are voids in the rock or incomplete layers of rock. The best material is solid rock or sedimentary material. Soils with cobble stone are not recommended. There are different types of heads used in the pilot-hole process, and they depend on the geological material.


The equipment used in a horizontal directional drilling depends on the outer diameter of the pipe, length of the run, ground conditions and the surroundings above ground. For the large bores, directional drills equipped with as much as 450 000 kg (or more) of thrust/pullback is used in conjunction with a mud reclaimer, excavator, and multiple pumps and hoses to supply the drilling fluid to the drillstem. Directional drilling stem is made from heat-treated high-carbon steel for strength and ships in diameters of 8 – 15 cm. Drill stem sections are manufactured in 3.0 or 4.6 and also 9.1 meter lengths and have male threading on one end, and female on the other. It is common for a directional drill to carry as much as 305 m of rod on board. Drilling heads come in multiple designs and depends on the rock or soil being penetrated. The drilling head has multiple water ports to allow removal of material. A talon bit involves the carbide-tipped cutters. These allow for steering and cutting the material. Another head is a mud-motor that is used in rocky landscapes.

Furthermore, supporting equipment is needed to assist directional-drilling or HDD to work smoothly, such as drilling mud recycling system, shale shaker, mud cleaner, centrifugal pump, mud tanks, etc.


Directional boring is used for installing infrastructure such as telecommunications and power cable conduits, water lines, sewer lines, gas lines, oil lines, product pipelines, and environmental remediation casings. It is used for crossing waterways, roadways, shore approaches, congested areas, environmentally sensitive areas, and areas where other methods are costlier or not possible. It is used instead of other techniques to provide less traffic disruption, lower cost, deeper and/or longer installation, no access pit, shorter completion times, directional capabilities, and environmental safety.

The technique has extensive use in urban areas for developing subsurface utilities as it helps in avoiding extensive open cut trenches. The use requires that the operator have complete information about existing utilities so that he can plan the alignment to avoid damaging those utilities. Since uncontrolled drilling can lead to damage, different agencies/government authorities owning the urban right-of-way or the utilities have rules for safe work execution. For standardization of the techniques, different trenchless technology promoting organizations have developed guidelines for this technique.


The process starts with receiving hole and entrance pits. These pits will allow the drilling fluid to be collected and reclaimed to reduce costs and prevent waste. The first stage drills a pilot hole on the designed path, and the second stage (reaming) enlarges the hole by passing a larger cutting tool known as the back reamer. The reamer’s diameter depends on the size of the pipe to be pulled back through the bore hole. The driller increases the diameter according to the outer diameter or the conduit and to achieve optimal production. The third stage places the product or casing pipe in the enlarged hole by way of the drill stem; it is pulled behind the reamer to allow centering of the pipe in the newly reamed path.

Horizontal directional drilling is done with the help of a viscous fluid known as drilling fluid. It is a mixture of water and, usually, bentonite or polymer continuously pumped to the cutting head or drill bit to facilitate the removal of cuttings, stabilize the bore hole, cool the cutting head, and lubricate the passage of the product pipe. The drilling fluid is sent into a machine called a reclaimer which removes the drill cuttings and maintains the proper viscosity of the fluid. Drilling fluids hold the cuttings in suspension to prevent them from clogging the bore. A clogged bore creates back pressure on the cutting head, slowing production.

Locating & Guidance

Location and guidance of the drilling is an important part of the drilling operation, as the drilling head is under the ground while drilling and, in most cases, not visible from the ground surface. Uncontrolled or unguided drilling can lead to substantial destruction, which can be eliminated by properly locating and guiding the drill head.

There are three types of locating equipment for locating the bore head: the walk-over locating system, the wire-line locating system and the gyro guided drilling, where a full inertial navigation system is located close to the drill head. In first system a sonde, or transmitter, behind the bore head registers angle, rotation, direction, and temperature data. This information is encoded into an electro-magnetic signal and transmitted through the ground to the surface in a walk-over system. At the surface a receiver (usually a hand-held locator) is manually positioned over the sonde, the signal is decoded and steering directions are relayed to the bore machine operator. The wire-line system is a Magnetic Guidance System. With a Magnetic Guidance System (MGS), the tool reads Inclination and Azimuth. The MGS, also has a secondary means of location verification utilizing wire grids laid on the ground surface. It is the only system that has the capability of verifying the location. This information is transmitted through the wire-line fitted within the drill string. At the surface, the Navigator in the drill cab performs the necessary calculations to confirm the parameters have been met. The MGS even without the use of the wire grid has been accurate to almost 2 km with an accuracy of 1.5 m accuracy. The gyro based system is fully autonomously working and therefore one of the most accurate system where sufficient diameter (200 mm) is available and where long distances (up to 2 km) have to be performed with small deviation (less than 1 m position error). All three systems have their own merits, and a particular system is chosen depending upon the site requirements.


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