Inspection of High Consequence Line Provides Critical Insight

Published by , Digital Assistant Editor
Energy Global, Monday, 19 March 2018 16:26

For pipelines transporting corrosive products, regular monitoring and inspection is vital to ensure long term operation and environmental safety compliance. Recent high-profile pipeline failures have focused increased regulatory scrutiny on the integrity assessment and management of pipeline assets throughout the world. This increase in scrutiny is even more pronounced for pipelines deemed “unpiggable.” When an operator requested an ultrasonic in-line inspection on a pipeline in an environmentally sensitive area, high resolution data provided a complete understanding of the internal condition of their asset, allowing for confident maintenance planning.


The inspected pipeline was a sulfuric acid pipeline, located in an environmentally sensitive area. The pipeline had been regularly monitored using hand-held spot ultrasonic (UT) inspection, and had undergone a number of section replacements after several failures, particularly at pipeline bends. Although spot UT can be an effective inspection method, it does not take data measurements of the entire pipeline, but rather takes individual wall thickness measurements at specific intervals along the pipeline surface. Due to the sensitivity of the surrounding environment and corrosive nature of the pipeline product, the performance of an in-line inspection was critical in understanding the full internal condition of the line.


There were a number of challenging factors to consider prior to the performance of the in-line inspection. The configuration of the pipeline was such that a number of traditional inspection technologies were not capable of successfully navigating the pipeline. For example, there were numerous 1.0D bends located along the length of the line. For traditional in-line inspection tools, these kinds of navigational features do not allow for the tool to successfully pass through the pipe. It was critical that the in-line inspection tool chosen for this inspection be capable of navigating the challenging configuration of the pipeline. Another component to consider was the pipeline’s liquid product. Since the line carried sulfuric acid, additional actions were taken to ensure the successful inspection of the pipeline. In order to collect accurate data, the tool was contained within a diesel slug with a batch pig, and flowed through the line with 5000 gallons ahead and 10 000 gallons behind, propelled by nitrogen. By using a batching system, the tool was able to both navigate the line and collect high resolution data.


The inspection was successfully performed on the pipeline, and the data was analysed. Interestingly, the data revealed indications of eddy damage near every circumferential weld. These welds were located where newly repaired pipe had been installed. In these areas of newly installed pipe, higher rates of corrosion and erosion were observed. There were also indications of hydrogen grooving adjacent to welds, as seen in Figure 1. However, there were no areas of the pipeline that required immediate remediation.

Figure 1. Inspection data indicating areas of hydrogen grooving along the internal surface of the pipeline.

It was recommended that the areas of deeper weld penetration undergo frequent monitoring, and suggested inspection intervals were presented to the facility. The pipeline was subsequently inspected multiple times in the following years, using ultrasonic in-line inspection. The data from each inspection run was then compared, in order to comprehensively monitor corrosion rates. By performing recurring run comparisons, the rate of any damage occurring on the line could be quantified on a regular basis. Run comparison analyses are largely effective in providing an accurate guideline for future maintenance planning.


By performing repeatable and regular in-line inspections on the pipeline over the course of its lifetime, the operator was able to gauge the complete condition of the asset, identifying localized areas of erosion/corrosion and eliminating the problematic failures that have historically impacted this particular asset. The comprehensive inspection strategy ultimately provided assurance that the asset would continue to operate efficiently, achieving considerable cost savings and peace of mind.



Corrosion under insulation poses major threat to offshore asset integrity


The battle against corrosion is an ever-present issue for the offshore oil and gas industry, with structures, pipework, and equipment widely exposed to seawater and humid, salty air.

Corrosion under insulation (CUI) is a major and well-understood threat, and the industry is researching new technology to help identify the impact earlier and more reliably. Mainly, CUI affects steel components, which corrode when they are in contact with water and air.

Insulation of plant and pipework can create a space where water can collect and rest against the metal surface over extended periods of time. With outdoor equipment, even very small gaps in insulating cladding can let in sufficient volumes of water to cause significant corrosion issues.

Advances in imaging technology are providing offshore maintenance crews with much more data on the ‘hidden’ condition of their assets than was available 10 years ago. (Photo courtesy Bilfinger Salamis)

Advances in imaging technology are providing offshore maintenance crews with much more data on the ‘hidden’ condition of their assets than was available 10 years ago. (Photo courtesy Bilfinger Salamis)

A further dilemma created by insulation is that it can hide the effects of the corrosion from view, so that a heavily corroded pipe can appear normal when visually inspected. But by the time the effects have become clearly visible from the outside – often in the form of particles of oxidized metal or discolored water running off – significant damage may already have occurred.

Removing insulation to check the condition of pipework is a laborious process and a costly method of assessing the condition of an asset. Maintenance specialists have developed a suite of different solutions that can make managing CUI across an installation more efficient and help ensure pipes and structures conform to HSE guidelines.


The biggest cost associated with inspecting for corrosion is manpower, and this is exacerbated in the case of offshore facilities – mobilizing the right personnel onboard and ensuring that they receive the correct briefing is a time-consuming process. The focus must therefore be on minimizing the resources needed to carry out the work. The preferred approach is for the inspection and fabric maintenance departments to work together, using three-man teams comprising an inspector, insulator and painter, all of whom are rope access-qualified. Keeping the teams as small as possible can lead to considerable reductions in cost.

It is better still to avoid the process of transporting new people to site to perform an inspection by instead training team members already on location to handle inspection work. Advances in technology to help automate the process have played a big part in making this possible, increasing the efficiency and effectiveness of inspection crews. Equipping teams with CUI detection tools such as digital radiography and pulsed eddy current (PEC) technology can significantly speed up site inspection processes and improve the likelihood of early detection.

Although radiographic and PEC imaging are not new, the techniques used to perform inspections have advanced rapidly. Previously each radiographic exposure took several minutes to capture and subsequently needed to be processed using lab equipment. These steps can now be taken in a matter of seconds and images can be viewed on the spot on a mobile device.

As recently as five years ago PEC readings needed to be performed on a point-to-point basis, making it time-consuming to capture all the angles and positions required to scan a length of pipework. In response, Bilfinger worked with imaging specialist Eddyfi to develop a system that runs continuously. This cuts the time taken and significantly increases the number of data points available, providing greater certainty of results. Using mobile data processing devices, engineers can now output easy-to-interpret condition reports showing the location and extent of any defects without any need for desktop analysis. This means response times to priority corrosion issues can be much faster.


Bilfinger was called in by a contractor operating a platform for a major global energy company to renew the insulation on all exterior pipework where CUI was detected. The existing insulation was mineral wool, enclosed in neoprene cladding, and the cause of the CUI in each case was failure of the elastomeric sealant used in the joints between sections.

Where replacements were needed, the mineral wool was replaced with foam glass. This was clad in banding tape sealed with Terostat PC vapor-barrier mastic, a long-life sealant proven to deliver better resistance than elastomeric options. The insulation was applied in the form of pre-fabricated shells supplied tailor-made, allowing fast installation on site and reducing costs.

The scale of the project, which involved replacing hundreds of meters of insulation, meant that the works took place over several months. Throughout delivery, the project team provided a monthly report with information on productivity, tool-time, costs, man allocation hours, work pack tracker, health safety, environment and quality CUI statistics and linear distance re-insulated.


CUI is critical, especially where ageing infrastructure is involved, and the current trend for maximizing the lifespan of large pieces of offshore infrastructure presents increased challenges, especially at mature fields on the UK continental shelf. Failure to manage CUI can, at best, lead to expensive and time-consuming maintenance operations; at worst, it can pose a major threat to the safety of facilities and personnel, so this is not an area offshore operators can afford to overlook.

The financial burden involved in performing inspections can be significant, but advances in both inspection technology and strategies have dramatically increased the efficiency of the process in recent years, decreasing the temptation to push back or skip what is an essential safety monitoring process.

Stopping corrosion in the LNG sector

LNG Industry

Published by , Editorial Assistant

While corrosion is a serious issue in virtually all oil, gas, pipeline, and industrial facilities, it is a particular challenge for the LNG sector, whose facilities must remain corrosion resistant despite rapid growth in areas prone to high humidity, rainfall, and monsoons.

According to the International Gas Union (IGU) 2017 World LNG Report, global LNG trade set a record for the third consecutive year, 258 million t, with the greatest growth in China, India, and Pakistan, which have seasonal monsoons.

In such conditions, the traditional barrier type coatings that are commonly reapplied every few years do not hold up, and often cannot be applied due to flash rusting (rust occurring within minutes or hours) caused by the wet, humid environment.

The frequent required maintenance is disruptive to production, requiring blasting off the old coatings, cleaning the surface, and reapplying multiple coatings. Despite this costly process, excessive corrosion of LNG vessels and carbon steel assets can lead to leaks, fires and accidents, as well as accelerate premature replacement.

Now an innovative coating approach is providing LNG facilities a long-term solution to fighting atmospheric corrosion even in monsoon vulnerable environments, while minimising production downtime and increasing safety. As an added plus for countries like China that are concerned about pollution, the application involves no Volatile Organic Compounds (VOCs), a hazardous component of traditional paints.

Protecting LNG Assets from Corrosion

Southeast China’s Zhejiang province has high humidity, annual average rainfall of 1000 mm – 1900 mm, and frequent typhoons in late summer.

In this region, the Zhoushan LNG Project is located in the Zhoushan Economic Development Zone amid these challenging conditions. As the region’s first import LNG receiving station project in which private enterprise is the main investor, total project investment is more than US$1.45 billion.

The project includes a LNG receiving station, LNG terminal, and pipe connection line, which is being constructed in phases, with completion and operation slated for 2020. It is operated by Xinao Group Co., Ltd., a wholly-owned subsidiary of ENN (Zhoushan) Liquefied Natural Gas Co., Ltd.

However, in phase I of the LNG project, traditional corrosion protection, which typically involves applying polymer paints and rubber type coatings, was ineffective due to very rainy, humid, windy conditions. Such coatings, in fact, often could not be applied because the humidity level was too high and the steel kept flash rusting.

While such methods can create a physical barrier to keep corrosion promoters such as water and oxygen away from steel substrates, this only works until the paint is scratched, chipped, or breached and corrosion promoters enter the gap between the substrate and coating. Then the coating can act like a greenhouse – trapping water, oxygen and other corrosion promoters – which allows the corrosion to spread.

Traditional solvent-based paints also posed another problem. When the solvents evaporate, they release VOCs, which are a source of air pollution, and contain a variety of chemicals linked to adverse health effects. For this reason, China has moved toward coatings that eliminate organic solvents, such as water-based paints.

In response, when the Xinao Group sought long term, external, corrosion protection for two fire fighting water tanks, the company turned to EonCoat, a spray applied inorganic coating from the Raleigh, North Carolina-based company of the same name. EonCoat represents a new category of tough, Chemically Bonded Phosphate Ceramics (CBPCs) that can stop corrosion, ease application, and reduce production downtime even in very wet, humid, monsoon susceptible conditions.

In contrast to traditional polymer coatings that sit on top of the substrate, the corrosion resistant CBPC coating bonds through a chemical reaction with the substrate, and slight surface oxidation actually improves the reaction. An alloy layer is formed. This makes it impossible for corrosion promoters like oxygen and humidity to get behind the coating the way they can with ordinary paints.

Although traditional polymer coatings mechanically bond to substrates that have been extensively prepared, if gouged, moisture and oxygen will migrate under the coating’s film from all sides of the gouge.

By contrast, the same damage to the ceramic coated substrate will not spread corrosion in LNG projects because the carbon steel’s surface is turned into an alloy of stable oxides. Once the steel’s surface is stable (the way noble metals like gold and silver are stable) it will no longer react with the environment and cannot corrode.

Visible in scanning electron microscope photography, EonCoat does not leave a gap between the steel and the coating because the bond is chemical rather than mechanical. Since there is no gap, even if moisture was to get through to the steel due to a gouge, there is nowhere for the moisture to travel. This effectively stops atmospheric corrosion of LNG carbon steel assets.

The corrosion barrier is covered by a ceramic layer that further resists corrosion, fire, water, abrasion, impact, chemicals, and temperatures up to 400°F. Beyond this, the ceramic serves a unique role that helps to end the costly maintenance cycle of replacing typical barrier type coatings every few years.

“In LNG installations, including receiving stations, terminals, and pipeline, if both the ceramic layer and the alloy layer are ever breached, the ceramic layer acts as a reservoir of phosphate to continually realloy the steel,” explains Merrick Alpert, President of EonCoat. “This ‘self heals’ the breach, depending on its size, and stops the corrosion if necessary. This capability, along with the coating’s other properties, enables effective corrosion protection for the life of the asset with a single application.”

The Xinao Group has successfully coated one Zhoushan LNG Project fire fighting water tank with the spray applied inorganic coating, which is compatible with a wide range of commonly used topcoats, and the other tank is expected to be completed in January 2018.

Because of the ceramic coating’s multiple layers of corrosion protection, and the ability to ‘self heal’ breaches, the LNG project is on track to see long term protection of its equipment, effectively breaking the costly cycle of blasting and repainting every few years.

Beyond corrosion resistance, LNG operation managers or corrosion engineers looking to reduce costs are finding additional advantages to CBPC coatings like EonCoat.

For instance, one of the ways China is working to mitigate the negative effects of air pollution is by turning to green alternatives such as CBPC coatings, which are inorganic and non-toxic, so there are no VOCs, no HAPs and no odor. This means the non-flammable coatings can be applied safely even in confined spaces, and satisfy the same goals as water-based paints.

Such CBPC coatings consist of two non-hazardous components that do not interact until applied by a standard industrial plural spray system like those commonly used to apply polyurethane foam or polyuria coatings.

One of the greatest additional benefits is the quick return to service that minimises facility downtime. The time saved on an anti-corrosion coating project with the ceramic coating comes both from simplified surface preparation and expedited curing time.

With a typical corrosion coating, near white metal blast cleaning (NACE 2 / SSPC-SP 10) is required to prepare the surface. But with the ceramic coating, only a NACE 3 / SSPC-SP 6 commercial blast is typically necessary.

For corrosion protection projects using typical polymer paints such as polyurethanes or epoxies, the cure time may be days or weeks before the next coat of a traditional ‘three part system’ can be applied, depending on the product. The cure time is necessary to allow each coat to achieve its full properties, even though it may feel dry to the touch.

With traditional coatings, extensive surface preparation is required and done a little at a time to avoid surface oxidation, commonly known as ‘flash rust’, which then requires re-blasting. But with CBPC coatings, the flash rust is not just acceptable but is desirable. The reason for this unique CBPC characteristic relates to the fact that the presence of iron in the rust aids in the creation of the magnesium iron phosphate alloy layer. It is this alloy layer that allows CBPCs to so effectively protect carbon steel from corrosion.

In contrast, a corrosion resistant coating for carbon steel utilising the ceramic coating in a single coat requires almost no curing time. Return to service can be achieved in as little as one hour. This kind of speed in getting an asset producing again can potentially save hundreds of thousands of dollars per day in reduced downtime in LNG applications.

With atmospheric corrosion a perennial problem for LNG facilities with massive carbon steel structures, the utilisation of CBPC coatings that can control corrosion for decades will only help the bottom line.

Protecting Steel Pipelines Using Vapor Phase Corrosion Inhibitors


A recent study from the U.S. Department of Transportation found that between 2006-2010, almost a fourth of significant onshore hazardous liquid pipeline incidents were caused by corrosion, along with a fifth of significant gas transmission pipeline incidents. According to “The State of the National Pipeline Infrastructure,” released by the Pipeline and Hazardous Materials Safety Administration (PHMSA), 4 percent of significant distribution system incidents during 2008-2010 were blamed on corrosion.

These statistics only begin to highlight the importance of protecting gas and oil pipelines from the corrosion failures that can result in expensive repairs, pipeline failure or even loss of life.

1Inevitable Problem

Pipeline corrosion is inevitable and immediate. The question is how long it will take before the corrosion will eat away enough of the piping to cause a problem. Many factors play into the equation of whether a pipeline will have corrosion problems in five, 10 or 20 years. This depends on the corrosiveness of the pipeline fluid, the thickness of the pipe and the level of corrosion protection.

An excellent method for fighting costly corrosion issues and encouraging the longest possible service life is the use of Vapor phase Corrosion Inhibitors (VpCIs). VpCIs are able to perform beyond traditional methods of corrosion protection because of their ability to work effectively in the liquid phase, vapor phase and at the sensitive liquid-vapor interface. They are also adaptable to multiple application methods including fogging, painting, hydro-testing, injection under insulation, injection into flow streams and more.

VpCI technology works by emitting a vapor from the VpCI source, whether applied in a powder, liquid or other form. When this vapor reaches a metal surface, it condenses and adsorbs — or forms a monomolecular protective layer — on the metal surface. This layer is highly hydrophobic and protects the metal from the attack of corrosive agents like moisture. It also neutralizes the electrical surface potential of the metal so that oxygen cannot interact with the metal to create a corrosion initiation site. An added benefit is that many VpCI applications have a self-replenishing capability, where new VpCI ions flow in to replace others that might be knocked away by scratching or marring of a protected surface. In the case of coatings, these VpCIs inhibit corrosion from creeping from areas of coating damage to the surrounding metal.

Pipeline Issues: Construction, Post-Construction, Operation

Corrosion precautions must be taken even prior to pipeline construction. While PHMSA requires that steel piping installations in the U.S. be externally coated for corrosion inhibition and also protected cathodically, internal protection can fall by the wayside.

Manufacturers may face problems simply getting the piping to the field without internal rust. Historically, pipe internals have been protected with heavy, wax based coatings, if they are treated at all. While these coatings can work, they need to be coated on all metal surfaces to be effective. Further, they are difficult to remove, when the pipe system gets commissioned. Conversely, VpCIs disperse and coat all internal metallic surfaces with a monomolecular protective layer. VpCI in powder or liquid form can be applied by fogging and left inside the pipes until they are installed.

After a pipe is installed below or above ground, it is flushed and hydro-tested for leaks. This is normally done with untreated water, leaving the pipe in a damp condition that can lead to rusting. In this case, VpCIs can be incorporated directly into the hydro-testing water (whether salt or fresh) so that the pipe internals are protected during and after the hydro-testing process.

Once a pipe is in operation with fluids running through it, the main concern becomes top of the line corrosion. Less corrosion will occur in areas of the pipe where the fluids are flowing, but the void space at the top of the pipe is left vulnerable to a mixture of moisture, air and corrosive gases that encourage corrosion. Though some pipelines may use no corrosion control at all, even traditional contact corrosion protection is limited because it is carried through the fluid and can only protect surfaces in direct contact with the fluid in the pipe. In contrast, VpCIs have the flexibility of working in the vapor phase, as well as the liquid phase. They can also provide protection to the critical liquid-vapor interface where it is difficult to provide continuous corrosion protection.

Another corrosion trouble spot is pipeline crossings, where pipes run through an extra casing that is intended to allow better pipe access but that tends to promote corrosion in the annular space between the internal and outer pipe. VpCI filling can be used to enhance the effect of cathodic protection in this situation and even reduce its need.

A pipeline rupture at any of these locations could be disastrous in terms of public safe4ty alone. Add to this the potential costs of replacement, downtime and environmental cleanup, and then investment in corrosion inhibitors produces a significant return on investment.

Facility Issues: Equipment, CUI, Storage Tanks

Pipelines cannot function without periodic pumping stations and production facilities located along their route. These structures face corrosion problems common for many industrial facilities. Pumping stations operate with standard equipment such as pumps, turbines and motors. Equipment like this can experience external corrosion where paint is chipped off or never existed or where corrosive elements exist within a lubricating system.

Corrosion in these locations poses serious loss through increased downtime and maintenance costs. Many of the same issues can occur at production facilities, and they also stand to benefit from the many available forms of VpCI protection, such as coatings, additives and powders.

Another significant problem in the petrochemical industry is corrosion under insulation (CUI). Plants often contain pipes carrying extremely high or low temperature fluids, and these pipes must be insulated for the safety of plant personnel. Unfortunately, this is a corrosion-promoting trap, where moisture easily finds its way below the insulation’s surface to start the corrosion process. The insulation in turn hides what is happening, making corrosion difficult to detect. As another testament to the flexibility of VpCI application, this situation can be treated by injecting VpCI right through the insulation and installing a corrosion detection system to monitor the pipe’s condition.

Oil and gas processing facilities naturally contain many storage tanks, which can be at risk for corrosion on tank bottoms. Though cathodic protection can be used and a corrosion rate monitoring system installed beneath the unseen storage tank floor, this method has limitations. Injecting VpCI slurry in the space below tank bottoms provides enhanced protection as its vapor is allowed to spread out and protect surfaces that cathodic protection cannot reach.


While corrosion in gas and oil pipelines and facilities is an inevitable threat, it is also very treatable. VpCI technology offers superior protection adaptable to many pipeline features, protecting areas not reached by traditional corrosion inhibitors and supplying more continuous protection where cathodic protection fails.

When weighing protection costs vs. benefits, it is important to consider that the total cost of pipeline failure is several magnitudes higher than the cost of prevention. Included in the costs of failure are unplanned downtime, labor costs for replacing the failed pipe or equipment and environmental contamination costs. When these liabilities come into play, and when considering that VpCI protection of an entire plant can cost less than traditional protection of one component, the use of VpCI protection becomes very attractive and logical.

ISO Standards for use in the oil and gas industry

images         download
The International Association for Organization (ISO) & the International Association of Oil and Gas Producers (IOGP) latest published a full page on  ISO Standards for use in the oil & gas industry

download2  download (1)      download (2)

But here in Malaysia normally we refer to own Malaysia Standard (MS) and ASTM or ASME standard.

Petronas receives tallest, heaviest fractionator process column in Malaysia

 From Astro Awani

Bernama | Published on June 26, 2016 21:21 MYT

KUALA LUMPUR: Petronas has received the tallest and heaviest propylene fractionator process column in Malaysia for the steam cracker facility located within its Pengerang Integrated Complex (PIC) in Pengerang, Johor.

Petronas receives tallest, heaviest fractionator process column in Malaysia
Petronas and Toyo personnel welcoming the arrival of Malaysia’s tallest and heaviest fractionator process column in Pengerang today. – BERNAMApic
In a statement, Petronas senior vice president and CEO of Petronas Refinery and Petrochemical Corporation Sdn Bhd (PRPC), Colin Wong Hee Huing said the fractionator has been recognised by the Malaysia Book of Records as the tallest and heaviest process column in Malaysia.
The state-of-the-art equipment was received on June 25.
Wong said this complemented the overall development of the PIC, which is poised for its refinery start-up by early 2019.
The PIC is a mega-scale, high-complexity development consisting of 23 process plants for refinery, steam cracker, petrochemicals and associate facilities.
The project is entering the construction phase and is progressing as scheduled. “We are optimistic of delivering this development within a relatively short timeframe of 52 months from when we reached our Final Investment Decision (FID) in April 2014. “We are now at the mid-point of the project schedule and on track towards achieving the overall PIC start-up in the first quarter of 2019,” he added.

The process column travelled eight days aboard the Jumbo Maritime-operated vessel MV Fairmaster, and all the way from the Hyundai Mipo Dockyard in South Korea, before arriving at the Material Offloading Facility (MOLF) port in Tanjung Setapa, Johor. The vessel also carried a smaller-scale propylene fractionator and an ethylene fractionator.

All three process columns are part of the main structures for PIC’s steam cracker complex, to be constructed by a consortium of Toyo Engineering Corporation and Toyo Engineering & Construction Sdn Bhd.

The largest ship in the world?

Pengerang power plant update

First gas turbine for Petronas’ Pengerang power plant arrives

Arriving on Monday at the Tanjung Setapa Material Offloading Facility within the Refinery and Petrochemical Integrated Development (Rapid) project site, the first Siemens SGT5-8000H gas turbine was received by representatives and management officials from the Johor port authorities, Petronas as well as the consortium of Siemens AG, Siemens Malaysia and MMC Engineering Services Sdn Bhd.

The consortium was awarded the engineering, procurement, construction and commissioning contract for the 1,220 MW plant in May 2014.

Siemens Malaysia said in a statement that the turbine, measuring 13.5 metres in length, 5.5 metres in height and 5.9 metres in width, arrived after a four-week trip.

It said the SGT5-8000H gas turbine is the most powerful gas turbine in commercial operation today.

“Each gas turbine unit comes with a waste-heat recovery steam generator (HRSG), associated mechanical and electrical systems and the instrumentation and control system. The steam produced in the HRSG will not only be partly used to supply up to 1,250 tonnes per hour of steam to various consumers within the Pengerang Integrated Complex (PIC), but will also be partly used to produce further electricity inside a triple stage steam turbine, hence optimising efficiency,” the company said.

On completion, the cogeneration plant will have a total installed capacity of about 1,220 MW, making it one of the largest and most efficient gas-fired power plants in the country. The plant will be one of six associated facilities that will be developed within PIC.

Floating LNG plant

Check out this video regarding LNG carrier. Engineering student will see the application of thermodynamic here.

Pengerang Gas Pipeline project on track

Pengerang Gas Pipeline project on track

PGB’s regasification terminal in Pengerang should be fully commissioned by the first quarter of 2018, the company says. –
He said the project would enable the initial supply of gas from the existing Peninsular Gas Utilisation (PGU) pipeline network to Pengerang and vice versa.”In addition, the group is expected to achieve final investment decision by the second quarter of 2016 for its Air Separation Unit project, also in Pengerang, for which the heads of agreement was signed in 2014,” he told the media after the group’s annual general meeting here today.

According to Shamsul Azhar, those are among the growth projects that keep the utility company busy this year onwards.

Although facing a challenging time, PGB managed to secure positive results for the 2015 financial year, he said.

Its revenue was sustained at RM4.5 billion last year, up 1.5 percent from RM4.4 billion in 2014, while profit rose 7.8 percent to RM2 billion mainly due to the tax incentives for the plant rejuvenation and revamp project that was fully completed in early 2015.

He also said PGB’s regasification terminal in Pengerang should be fully commissioned by the first quarter of 2018.

“At this point of time, it is about 25 percent completed,” he said, adding that the project would likely contribute to the company’s growth in terms of income and profitability moving forward.

On capital expenditure, he said PGB, which undertook a loan of US$500 million or RM2.2 billion from Mizuho Bank Ltd early this year, would use the bulk of the loan for its projects and also as a reserve for maintenance.

Asked on the demand for gas in Malaysia moving forward, Shamsul Azhar said PGB does not see demand for gas in the country reducing.

“In fact we are investing in a regasification terminal in Pengerang to basically cater for additional gas which will cater for future requirements,” he added.

PGB’s resilience, coupled with support from its shareholders, have enabled it to achieve an increase in market capitalisation to RM45 billion as at end-2015, further bolstering the prominence of the firm’s corporate branding in Malaysia.

A dividend of 60 sen per ordinary share for the year was approved, representing a normalised dividend payout ratio of 77 percent – a level that is on par with, if not better than, the industry average.