Pipeline Construction

Pipeline Construction

Pipeline construction is divided into three phases, each with its own activities: pre-construction, construction and post-construction.

Pre-Construction

Surveying and staking

Once the pipeline route is finalized crews survey and stake the right-of-way and temporary workspace. Not only will the right-of-way contain the pipeline, it is also where all construction activities occur.

Preparing the right-of-way

The clearly marked right of way is cleared of trees and brush and the top soil is removed and stockpiled for future reclamation. The right-of-way is then leveled and graded to provide access for construction equipment.

Digging the trench

Once the right-of-way is prepare, a trench is dug and the centre line of the trench is surveyed and re-staked. The equipment used to dig the trench varies depending on the type of soil.

Stringing the pipe

Individual lengths of pipe are brought in from stock pile sites and laid out end-to-end along the right-of-way.

Construction

Bending and joining the pipe

Individual joints of pipe are bent to fit the terrain using  a hydraulic bending machine. Welders join the pipes together using either manual or automated welding technologies. Welding shacks are placed over the joint to prevent the wind from affecting the weld. The welds are then inspected and certified by X-ray or ultrasonic methods.

Coating the pipeline

Coating both inside and outside the pipeline are necessary to prevent it from corroding either from ground water or the product carried in the pipeline. The composition of the internal coating varies with the nature of the product to be transported. The pipes arrive at the construction site pre-coated, however the welded joints must be coated at the site.

Positioning the pipeline

The welded pipeline is lowered into the trench using bulldozers with special cranes called sidebooms.

Installing valves and fittings

Valves and other fittings are installed after the pipeline is in the trench. The valves are used once the line is operational to shut off or isolate part of the pipeline.

Backfilling the trench

Once the pipeline is in place in the trench the topsoil is replaced in the sequence in which it was removed and the land is re-contoured and re-seeded for restoration.

Post Construction

Pressure Testing

The pipeline is pressure tested for a minimum of eight hours using nitrogen, air, water or a mixture of water and methanol.

Final clean-up

The final step is to reclaim the pipeline right-of-way and remove any temporary facilities.

Reference: “Pipeline Construction”. http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Pipeline Installation Method in Deepwater

Pipeline is a transportation of goods through a pipe. For underwater pipeline the most common goods is oil and gas. Generally pipeline is welding using 5G position with two kind welding techniques. First one is downhill, the most common use for pipeline. The welding start from above the pipe and go through the bottom of the pipe. Second is uphill, the opposite way of downhill. Pipeline welding using downhill technique because this technique is faster than uphill. But for toughness, uphill technique is still better than downhill. Celluloid is the most common welding consumable that use for welding in pipeline. For welding technique is depend on client requirement, but nowadays welding in pipeline is using MIG or for manual is GTAW.

The pipeline have some several parts, there are:

• Mainline. Mainline is the primary line that transport goods such as oil or gas from manifold to ship or rig.
• Tie-in. Tie-in contains of flange, pipe, and pipe bend. The function of tie-in is a connector between risers and mainline.
• Flange: Flange is a joint that can freely open or close. Flange is bolting not welding to make it easier to maintain.
• Pipe bend: A pipe that bend to transport the goods from mainline to riser.
• Riser: A part of pipeline to transport the goods from mainline to sea surface.

Generally for pipeline construction there are two kind of design, strain-based pipeline and stress-based pipeline. Stress-based pipeline is a conventional design of pipeline. The pipeline characteristic is stress-based, in the other word is the pipeline can bear the stress good enough. This is designed for safety use but the cost is expensive because using too many material. Nowadays the pipeline design is using strain-based design. It is cheaper and more efficient, but need a good calculation of design.

Pipe Laying

Installing pipeline underwater is called pipe laying. There are three types of laying, S-lay, J-lay, and nowadays there is a reeling installation. The different from three of them is the shape of the pipe when went from a barge to seabed. S-lay laying pipe usually use for small size of pipe, when J-lay and reeling is for big size installation.

Pipeline Construction Line

There are two types of pipeline construction, conventional construction and reeling. Nowadays contractor start change their pipeline construction to reeling method. Conventional construction is to construct the pipeline above the ship/ barge. In the other hand reeling construction is to make the pipe in land, reel it and take it to the sea.

The example of conventional pipeline method is on US EPCI company’s barge. Figure 1 is a flow chart of pipeline conventional method.

Figure 1. Conventional pipeline installation flowchart.

The barge will bring the pipe to the construction site, another barge also bring it into the site. In location site the barge will put down the anchor. Using a help from tugboat the barge need to get a good position of an anchor to hold the barge getting pulled by pipeline when the pipeline start to release from the barge. When it settle the barge start their construction line.

First the pipe from deck or barge will go into construction line. The pipe will went through beadstall. In beadstall, the pipe will be check the code, cleaning the pipe, and also some preheating is applied into the pipe. If there is something wrong with the pipe code or rejected the pipe will go to quarantine place. After preheating, the pipe will go to the station. Station is a place where the pipe start to weld, NDT test, coating, and in the end is release it into the seabed. How many station on the ship is depends on client demand, but usually there is 9 stations on the ship. First station is for root welding station. Welding technique use in project is depend on the client demand. When it finish it will go to other station to do another welding layer, and so on in other station until finishing the capping weld. After finishing the welding, NDT test will do to check the welding result. The most common NDT test is UT or nowadays is AUT. But sometimes radiography test also use to inspect the welding. If there is a problem, the construction line will stop and welder will be call to repair the welding. If it can't be repair, the pipeline will be cut off and replace with a new pipe. After the NDT station pipeline will go to the next station which is a coating station. In this station they will applied a coating for pipeline joint, a pipeline coating already installed in land. The coating that use for joint is Heat Shrink Sleeves (HSS) coating. After finishing the coating, anode installation will be done, depends on client demand. Later the pipe will be release into the sea. Pipe will go from the barge trough a stinger and later go into the seabed. The pipeline will leave the barge and went through the seabed create an "S" shape. That pipe laying is called S-lay pipe.

Reference:  Hutagalung, Andi A., Albert Hutama. 2013. “Phase III Preparation CAPEX NO102 and QC Department Batam Marine Base”. Bandung: ITB.

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Crack Propagation on Pipeline

Polyethylene (PE) is the primary material used for gas pipe applications. Because of its flexibility, ease of joining and long-term durability, along with lower installed cost and lack of corrosion, gas companies want to install PE pipe instead of steel pipe in larger diameters and higher pressures. As a result, rapid crack propagation (RCP) is becoming a more important property of PE materials.

This article reviews the two key ISO test methods that are used to determine RCP performance (full-scale test and small-scale steady state test), and compare the values obtained with various PE materials on a generic basis. It also reviews the status of RCP requirements in industry standards; such as ISO 4437, ASTM D 2513 and CSA B137.4. In addition, it reviews progress within CSA Z662 Clause 12 and the AGA Plastic Materials Committee to develop industry guidelines based on the values obtained in the RCP tests to design against an RCP incident.

Background

Although the phenomenon of RCP has been known and researched for several years 1, the number of RCP incidents has been very low. A few have occurred in the gas industry in North America, such as a 12-inch SDR 13.5 in the U.S. and a 6-inch SDR 11 in Canada, and a few more in Europe.

With gas engineers desiring to use PE pipe at higher operating pressures (up to 12 bar or 180 psig) and larger diameters (up to 30 inches), a key component of a PE piping material - resistance to rapid crack propagation (RCP) - becomes more important.

Most of the original research work conducted on RCP was for metal pipe. As plastic pipe became more prominent, researchers applied similar methodologies used for metal pipe on the newer plastic pipe materials, and particularly polyethylene (PE) pipe 2. Most of this research was done in Europe and through the ISO community.

Rapid crack propagation, as its name implies, is a very fast fracture. Crack speeds up to 600 ft/sec have been measured. These fast cracks can also travel long distances, even hundreds of feet. The DuPont Company had two RCP incidents with its high-density PE pipe, one that traveled about 300 feet and the other that traveled about 800 feet.

RCP cracks usually initiate at internal defects during an impact or impulse event. They generally occur in pressurized systems with enough stored energy to drive the crack faster than the energy is released. Based on several years of RCP research, whether an RCP failure occurs in PE pipe depends on several factors:

1.            Pipe size.

2.            Internal pressure.

3.            Temperature.

4.            PE material properties/resistance to RCP.

5.            Pipe processing.

Typical features of an RCP crack are a sinusoidal (wavy) crack path along the pipe, and “hackle” marks along the pipe crack surface that indicate the direction of the crack. At times, the crack will bifurcate (split) into two directions as it travels along the pipe.

Test Methods

The RCP test method that is considered to be the most reliable is the full-scale (FS) test method, as described in ISO 13478. This method requires at least 50 feet of plastic pipe for each test and another 50 feet of steel pipe for the reservoir. It is very expensive and time consuming. The cost to obtain the desired RCP information can be in the hundreds of thousands of dollars.

Due to the high cost for the FS RCP test, Dr. Pat Levers of Imperial College developed the small-scale steady state (S4) test method to correlate with the full-scale test3. This accelerated RCP test uses much smaller pipe samples (a few feet) and a series of baffles, and is described in ISO 13477. The cost of conducting this S4 testing is still expensive, but less than FS testing. Several laboratories now have S4 equipment. A photograph with this article shows the S4 apparatus used by Jana Laboratories.

Whether conducting FS or S4 RCP testing, there are two key results used by the piping industry; one is the critical pressure and the other is the critical temperature.

The critical pressure is obtained by conducting a series of FS or S4 tests at a constant temperature (generally 0°C) and varying the internal pressure. At low pressures, where there is insufficient energy to drive the crack, the crack initiates and immediately arrests (stops). At higher pressures, the crack propagates (goes) to the end of the pipe. The critical pressure is shown by the red line in Figure 1 as the transition between arrest at low pressures and propagation at high pressures. In this case, the critical pressure is 10 bar (145 psig).

Due to the baffles in the S4 test, the critical pressure obtained must be corrected to correlate with the FS critical pressure. There has been considerable research within the ISO community conducted in this area. Dr. Philippe Vanspeybroeck of Becetel chaired a working group - ISO/TC 138/SC 5/WG RCP - that conducted S4 and FS testing on several PE pipes 4. Based on their extensive research effort, the WG arrived at the following correlation formula 5 to convert the S4 critical pressure (Pc,S4) to the FS critical pressure (Pc,FS):

Pc,FS = 3.6 Pc,S4 + 2.6 bar (1)

It is important to note that this S4/FS correlation formula may not be applicable to other piping materials, such as PVC or polyamide (PA). For example, Arkema has conducted S4 and FS testing on PA-11 pipe and found a different correlation formula for PA-11 pipe 6.

The critical temperature is obtained by conducting a series of FS or S4 tests at a constant pressure (generally 5 bar or 75 psig) and varying the temperature 7. At high temperatures the crack initiates and immediately arrests. At low temperatures, the crack propagates to the end of the pipe. The critical temperature is shown by the red line in Figure 2 as the transition between arrest at high temperatures and propagation at low temperatures. In this case, the critical temperature is 35°F (2°C).

RCP In ISO

The International Standards Organization (ISO) product standard for PE gas pipe, ISO 4437, has included an RCP requirement for many years 8. This is because there were some RCP failures in early generation European PE gas pipes, and the Europeans had conducted considerable research on RCP in PE pipes. Also, European gas companies were using large-diameter pipes and higher operating pressures for PE pipes, both of which make the pipe more susceptible to RCP failures.

Below is the current requirement for RCP taken from ISO 4437:

Pc > 1.5 x MOP (2)

Where: Pc = full scale critical pressure, psig

MOP = maximum operating pressure, psig

Most manufacturers use the S4 test to meet this ISO 4437 RCP requirement. If the requirement is not met, then the manufacturer may use the FS test. Therefore, the ISO 4437 product standard requires that RCP testing be done, and also provides values for the RCP requirement.

RCP In ASTM

Until recently, ASTM D 2513 did not address RCP at all 9. The AGA Plastic Materials Committee (PMC) requested that an RCP requirement be added to ASTM D 2513, similar to the RCP requirement in the ISO PE gas pipe standard ISO 4437. The manufacturers agreed to include a requirement in ASTM D 2513 that RCP testing (FS or S4) must be performed. The ASTM product standard D 2513 does not include any required values.

PMC has agreed with this approach and will develop its own industry requirement in the form of a “white paper.” 10 The first draft was just issued within PMC with the following proposed requirement:

PC,FS > leak test pressure.

Leak test pressure = 1.5 X MOP.

RCP In CSA

CSA followed the direction of ASTM. The product standard CSA B137.4 11 requires that the RCP testing must be done. The values of the RCP test will be stipulated in CSA Z662 Clause 12, which is the Code of Practice for gas distribution in Canada. Clause 12 recently approved the requirement as shown nearby.

12.4.3.6 Rapid Crack Propagation (RCP) Requirements

When tested in accordance with B137.4 requirements for PE pipe and compounds, the standard PE pipe RCP Full-Scale critical pressure shall be at least 1.5 times the maximum operating pressure. If the RCP Small-Scale Steady State method is used, the RCP Full-Scale critical pressure shall be determined using the correlation formula in B137.4.

RCP Test Data

The critical pressure is the pressure - below which - RCP will not occur. The higher the critical pressure, the less likely the gas company will have an RCP event. In most cases, as the pipe diameter or wall thickness increases, the critical pressure decreases. Therefore, RCP is more of a concern with large-diameter or thick-walled pipe. Following are some typical critical pressure values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe.

PE Material S4 Critical Pressure (PC,S4) at 32°F (0°C)/Full Scale Critical Pressure (PC,FS) @ 0°C

Unimodal MDPE 1 bar (15 psig)/6.2 bar (90 psig)

Bimodal MDPE 10 bar (145 psig) /38.6 bar (560 psig)

Unimodal HDPE 2 bar (30 psig)/9.8 bar (140 psig)

Bimodal HDPE (PE 100+) 12 bar (180 psig)/45.8 bar (665 psig)

In general, the RCP resistance is greater for HDPE (high-density PE) than MDPE (medium-density PE). However, there is a significant difference when comparing a unimodal PE to a bimodal PE material, about a ten-fold difference.

Bimodal PE technology was developed in Asia and Europe in the 1980s. This technology is known to provide superior performance for both slow crack growth and RCP, as evidenced by the table. For the bimodal PE 100+ materials used in Europe and Asia, the S4 critical pressure minimum requirement is 10 bar (145 psig), which converts to 560 psig operating pressure. This means that with these bimodal PE 100+ materials, RCP will not be a concern. Today, there are several HDPE resin manufacturers that use this bimodal technology. Recently, a new bimodal MDPE material was introduced for the gas industry 12,13 with a significantly higher S4 critical pressure compared to unimodal MDPE - 10 bar compared to 1 bar.

Another measure of RCP resistance is the critical temperature. This is defined as the temperature above which RCP will not occur. Therefore, a gas engineer wants to use a PE material with a critical temperature as low as possible. Although critical temperature is not used as a requirement in the product standards, it is an important parameter, and perhaps should be given more consideration. Following is a table with some typical critical temperature values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe.

PE Material/Critical Temperature (TC) at 5 bar (75 psig)

Unimodal MDPE 15°C (60°F)

Bimodal MDPE -2°C (28°F)

Unimodal HDPE 9°C (48°F)

Bimodal HDPE -17°C (1°F)

Again, we see that RCP performance for HDPE is slightly better than MDPE, but there is a significant difference between bimodal PE and unimodal PE. The bimodal MDPE and HDPE materials have the lowest critical temperatures, which means the greatest resistance to RCP.

Conclusion

As gas companies use PE pipe in more demanding applications, such as larger pipe diameters and higher operating pressures, the resistance of the PE pipe to rapid crack propagation (RCP) becomes more important. In this article we have discussed the phenomenon of RCP and the two primary test methods used to determine RCP resistance - the S4 test and the Full Scale test. We reviewed the correlation formula between the FS test and S4 test for critical pressure. We have also discussed the two primary results of RCP testing - the critical pressure and the critical temperature.

ISO standards were the first to recognize the importance of RCP, especially in larger diameter pipe sizes, and incorporated RCP requirements in product standards, such as ISO 4437. The Canadian standards soon followed, and an RCP test requirement has been added to CSA B137.4. The required values for RCP testing are being added to the CSA Code of Practice in CSA Z662 Clause 12 for gas piping. ASTM just added an RCP requirement to its gas pipe standard ASTM D 2513. The corresponding AGA PMC project to develop RCP recommendations for required values from RCP testing is in progress.

In this article, we also discussed some results of RCP testing. In general, the HDPE materials have slightly greater RCP resistance than MDPE materials used in the gas industry. A more significant difference is observed when comparing unimodal PE materials to bimodal PE materials. Existing data indicate that bimodal HDPE materials show a significant increase in critical pressure compared to unimodal HDPE materials and also have considerably lower critical temperature values.

In addition, this bimodal technology has now just been introduced for MDPE. This bimodal MDPE material also has a significantly higher S4 critical pressure (10 bar vs. 1 bar) and a lower critical temperature than unimodal MDPE materials. With several PE resin manufacturers being able to produce bimodal PE materials, it is likely that in the near future, all PE materials used for the gas industry will be bimodal materials because of their superior RCP resistance.

Reference:

“Rapid Crack Propagation Increasingly Important in Gas Applications: A Status Report”, Dr. Gene Palermo, http://pipelineandgasjournal.com/rapid-crack-propagation-increasingly-important-gas-applications-status-report

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id

Horizontal Directional Drilling

For many decades the only way we could extract natural gas was to drill a well straight down into the ground. However, in many instances, this is not possible, not economically feasible, or simply not efficient. Technological advances now allow us to efficiently deviate from 'straight line' drilling, and steer the drilling equipment to reach a point that is not directly underneath the point of entry. While what is known as 'slant drilling', where the well is drilled at an angle instead of directly vertical, has been around for years, new technology is allowing for the drilling of tightly curved well holes, and even wells that can take a 90 degree turn underground.

Directional drilling is the process of drilling a curved well, in order to reach a target that is not directly beneath the drill site. This is useful in many circumstances where the area above the targeted deposit is inaccessible. For example, to reach reservoirs that exist under shallow lakes, protected areas, railroads, or any other area on which the rig cannot be set up, directional drilling is employed. It is also useful for long, thin reservoirs. These types of reservoirs are not efficiently mined with a vertical completion. However, horizontal entry into the reservoir allows it to be drained more efficiently. Directional drilling is especially useful for offshore locations. The cost of offshore drilling rigs can make it uneconomical to drill a single well. With directional drilling, the offshore rig can gain access to deposits that are not directly beneath the rig, meaning that 20 or more wells can be drilled from a single rig, making it much more cost effective to drill offshore.

Horizontal Drilling

The difference between traditional directional or slant drilling and modern day horizontal drilling, is that with directional drilling it can take up to 2,000 feet for the well to bend from drilling at a vertical to drilling horizontally. Modern horizontal drilling, however, can make a 90 degree turn in only a few feet! The concept of horizontal drilling is not new. In fact, the first patent for horizontal drilling was issued in 1891 to Robert E. Lee, for drilling a horizontal drainhole for a vertical well. The advances in technology and the increasing focus on accessing less accessible reservoirs to meet rising demand have allowed for a proliferation of horizontal drilling.

Horizontal drilling technologies have been heralded by many as the greatest advances since the conception of the rotary drilling bit. Horizontal drilling now accounts for 5 to 8 percent of active onshore wells in the U.S., and seems to be increasing every year. The ability of horizontal drilling to reach and extract petroleum from formations that are not accessible with vertical drilling has made it an invaluable technology. Horizontal drilling allows for an increase in the recoverable petroleum in a given formation, and even increases the production in fields previously thought of as marginal or mature. Horizontal drilling also allows for more economical drilling, and less impact on environmentally sensitive areas. In fact, in some areas in which drilling is not allowed for environmental reasons, it is possible to drill horizontal wells to the targeted deposit without harming the environment above. In addition, with this technology, fewer wells are needed to produce the same amount of hydrocarbons.

A number of advances were crucial to the progression of horizontal drilling. Measurement-while-drilling technology (or 'borehole telemetry') has allowed engineers and geologists to gain up-to-the-minute subsurface information, even while the well is being drilled. This avoids some of the complications of normal logging practices, and greatly increases the drilling engineer's knowledge of the well characteristics. Steerable downhole motor assemblies have also allowed for advances in horizontal drilling. While conventional drilling occasionally employs the use of downhole motors just above the drill bit to penetrate hard formations, steerable drilling motors allow the actual path of the well to be controlled while drilling.

There are three main types of horizontal wells; short-radius, medium-radius, and long-radius. Short-radius wells typically have a curvature radius of 20 to 45 feet, being the 'sharpest turning' of the three types. These wells, which can be easily dug outwards from a previously drilled vertical well, are ideal for increasing the recovery of natural gas or oil from an already developed well. They can also be used to drill non-conventional formations, including coalbed methane and tight sand reservoirs.

Medium-radius wells typically have a curvature radius of 300 to 700 feet, with the horizontal portion of the well measuring up to 3,500 feet. These wells are useful when the drilling target is a long distance away from the drillsite, or where reservoirs are spaced apart underground. Multiple completions may be used to gain access to numerous deposits at the same time.

Long-radius wells typically have a curvature radius of 1,000 to 4,500 feet, and can extend a great distance horizontally. These wells are typically used to reach deposits offshore, where it is economical to drill outwards from a single platform to reach reservoirs inaccessible with vertical drilling.

To give an idea of the effectiveness of horizontal drilling, the U.S. Department of Energy indicates that using horizontal drilling can lead to an increase in reserves in place by 2% of the original oil in place. The production ratio for horizontal wells versus vertical wells is 3.2 to 1, while the cost ratio of horizontal versus vertical wells is only 2 to 1. In carbonate formations, where 90 percent of horizontal drilling is done, productivity of horizontal wells is almost 400 percent higher than vertical wells, while they cost only 80 percent more.

Horizontal drilling is an important innovation that will likely find countless new applications as the technology is developed. With increasing demand for natural gas, innovations like these will be invaluable to securing and bringing to surface these much needed hydrocarbons.

Reference:

“Directional and Horizontal Drilling”.

http://www.naturalgas.org/naturalgas/extraction_directional.asp. 

George Gilbert Mattew

Student ID. 155 12 061

Course: KL4220 Subsea Pipeline

Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D./ Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id