Velesto Naga 7, a Jackup Rig Submerged in Offshore Malaysia

A jack-up rig owned by Malaysian drilling contractor Velesto tilted and submerged at a location offshore Sarawak, Malaysia on Tuesday, the rig owner said.

"The Board of Directors of Velesto Energy Berhad regrets to inform that an incident involving one of our rigs, Velesto Naga 7, occurred at the worksite due to rapid penetration into the formation on 3 May 2021, Monday, whilst operating in offshore Sarawak for a client. "The rig tilted and subsequently on 4 May 2021, Tuesday, VELESTO NAGA 7 submerged at the location. Drilling activities have not commenced and no well has been drilled," Velesto said. According to Velesto, all personnel on-board are safe on the rescue vessels, and majority have been transferred to Miri, Sarawak. The remaining personnel are in the process of being transferred, Velesto said Tuesday.

"The company is investigating the incident and evaluating options. The rig is covered by insurance and recovery efforts are ongoing and monitored," Velesto added. "The Company extends gratitude to all involved in the evacuation operation after the incident and the ongoing recovery efforts, including our client and all relevant authorities," Velesto said. To remind, Velesto late in March announced it had secured a drilling contract for the rig with ConocoPhillips in Malaysia. The estimated value of the contract is around $8 million. Under the contract, ConocoPhillips was to use the 2015-built, Gusto-designed, jack-up rig to drill up to three wells, with the start-up expected sometime in the first half of 2021. The Naga 7 is a three-legged jack-up delivered by China's China Merchants Heavy Industries in 2015. The rig was built to a GustoMSC design. It has a drilling depth capability of 30,000 feet (9144 meters) and has a rated operating water depth of 375 feet (114.3 meters).

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5:12:00 AM | 0 comments

TechnipFMC won the Limbayong deepwater development offshore Malaysia

Oilfield services company TechnipFMC has won a "substantial" contract by Petronas Carigali in Malaysia for the provision of subsea systems and associated equipment for the Limbayong deepwater development offshore Malaysia.  TechnipFMC will, through its subsidiary FMC Wellhead Equipment, be responsible of front-end engineering design, and integrated engineering, procurement, construction, installation, and commissioning of subsea production system, umbilicals, risers, and flowlines.  For TechnipFMC, a “substantial” contract ranges between $250 million and $500 million. The contract covers the development of 10 deepwater wells and their tieback to the Limbayong Floating Production Storage and Offloading (FPSO) unit in Malaysia. TechnipFMC will design, manufacture, deliver and install subsea equipment including subsea trees, manifolds, umbilicals, flexible risers, flowlines, jumpers, and other associated subsea hardware for the project. "The project will be executed from TechnipFMC’s Kuala Lumpur office and will leverage its local manufacturing plants in Malaysia," TechnipFMC said. As for the FPSO, according to World Energy Reports, a global FPSO database, Petronas in Oct 2020 issued a new tender to lease an FPSO for the Limbayong oil/gas field offshore Sabah Malaysia.  The FPSO is to be capable of producing 40,000 b/d oil, 90 mmcf/d gas and injecting 75,000 b/d water -- and have storage for 600,000 bbls. Local content requirements for FPSO fabrication favor local contractors. The lease will be for 12 yrs firm + 3 + 3 + 2 yr options. "Bids were submitted on 2 Feb 2021. MISC, Yinson, Bumi Armada and SIP are among the bidders. Award of FPSO contract likely to be in late 2021," World Energy Reports database shows. Petronas is the field operator and has 100% interest in Limbayong.

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5:51:00 PM | 0 comments

Hydrogen as natural gas comes under attack, become Pipeline Operators Concern.

(Bloomberg) --Three million miles of natural gas pipelines criss-cross the U.S., and the fight against climate change could render them all obsolete. The last two weeks alone illustrate the stakes. President Joe Biden canceled the permit for the $9 billion Keystone XL oil pipeline on his first day in office, a clear signal any new fossil fuel pipeline project in the U.S. will face long odds. His climate envoy, former Secretary of State John Kerry, warned that natural gas pipelines could become “stranded assets” within 30 years as the administration seeks to end carbon emissions from power plants. And NextEra Energy Inc. wrote off $1.2 billion of its investment in the Mountain Valley gas pipeline from West Virginia to Virginia, which has been tied up in regulatory and legal delays. So pipeline owners are eyeing another, possibly future-proof fuel: hydrogen. Unlike natural gas, hydrogen can be burned without pumping carbon dioxide into the air. Run it through a fuel cell to generate electricity and the only waste is water; produce hydrogen using electrolyzers powered by solar plants or wind farms and it becomes a way to store massive amounts of renewable energy—far more than any of today’s batteries can hold. And the best part for pipeline companies: getting it where it needs to be, in bulk, could require the same basic infrastructure that now carries natural gas. It could, in other words, be a savior for the businesses behind our fossil fuel infrastructure. Even as those same companies insist gas will play a role for years to come, many of them are talking up the potential of hydrogen. They’re launching projects to blend small portions of hydrogen into their existing networks to see how the equipment behaves. They’re running experiments to strip hydrogen out of that blended gas, for use at specific locations. And they’re exploring how they might eventually transition from one fuel to the other. “We see our gas network as an energy system that delivers molecules to our customers, and by 2050, the source of those molecules will be very different,” said Sheri Givens, vice president of U.S. regulatory and customer strategy at National Grid. “We see hydrogen as the low-carbon molecule of the 21st century.” But the hype is far from the reality. Some climate activists battling the industry over gas bans call the companies’ talk of hydrogen greenwashing. Gas businesses are downplaying the difficulty of switching from one fuel to the other, they say, trying to convince investors they’ll still be relevant in a zero-carbon world. “The industry’s always putting out things that might happen—if we just keep using gas right now,” said Matt Vespa, staff attorney with Earthjustice. So far, there’s more actual hydrogen activity in Europe and the U.K. than there is in the U.S., where some companies have expressed interest without revealing many specific plans. The then-chief commercial officer of Energy Transfer, the largest U.S. pipeline operator by revenue, last fall called hydrogen “a head scratcher” that, at least for now, doesn’t make sense. “At this point, we don't see anything close on the horizon around hydrogen,” said Marshall S. McCrea, now the company’s co-chief executive officer. The questions involved in hydrogen transport go beyond merely the will to pursue it. Gas pipeline owners can’t simply switch from one gas to the other without cutting off existing customers, so any transition would start with blending hydrogen into the existing stream of fuel. But even mixing the two—let alone replacing one with the other—poses technical problems that would need to be overcome. Compressors designed to move natural gas don’t work well with hydrogen, the lightest of all elements, and would likely need to be replaced. Some types of steel pipe become brittle and crack when exposed to hydrogen over time, whereas polymer pipes can easily handle hydrogen. “We must investigate this for every single pipe we put hydrogen into,” said Jack Brouwer, director of the advanced power and energy program at the University of California, Irvine, “but it’s a phenomenon we can manage because it’s slow.” Problem pipes and compressors could be replaced over the course of years, he said. Or pipes could be protected with coatings applied from the inside by robotic devices called pigs that are currently used for pipeline inspection and maintenance. “Just put some spray-painting equipment on that same device, and there you go, right down the whole pipeline,” he said. Pilot projects around the world have been designed to flush out problems and give companies a better sense of what other obstacles might lie ahead. In California, for instance, Sempra Energy has planned a series of demonstration projects that will test various concentrations of hydrogen in fuel blends—possibly up to 20%—in isolated pipeline segments made of polyethylene, steel, and a combination of the two. Another project will test technology to strip and compress hydrogen from the blended gas. “Since the infrastructure already exists and serves customers, we would submit that it’s in the public interest to keep using that infrastructure to help us decarbonize,” said Jonathan Peress, senior director of regulatory affairs for Sempra’s Southern California Gas Co. In July, a group of eleven European gas infrastructure companies presented a plan to build a dedicated hydrogen transport network, saying existing gas infrastructure can be modified to transport hydrogen at an affordable cost. The hydrogen network is set to reach 4,225 miles (6,800 kilometers) by 2030 and nearly 14,300 miles (23,000 kilometers) by 2040, three-quarters of which will consist of converted natural gas pipelines. National Grid in the U.K. has launched a series of hydrogen demonstration projects, including using the gas to heat homes, and has discussed establishing a hydrogen pipeline transmission network connecting the industrial centers along Britain’s east coast. In the U.S., the company is partnering with six national labs and other companies on a gas-mixing research effort called HyBlend. “The one thing that we have in the U.S. that we should be very proud of and is of huge value to us is we have a tremendous natural gas transportation and storage network,” said Alan Armstrong, chief executive officer of the Williams Companies, Inc., an energy infrastructure giant whose core business is natural gas. “It's a tremendous opportunity for us to really take advantage of and to make hydrogen more economical.”

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3:25:00 AM | 0 comments

2021 Worldwide Pipelines Opportunities

(PGJ Online) To say 2020 has been a volatile year would not even begin to describe what midstream and other energy sectors have endured over the better part of the past 12 months. The year, which began with optimism running high for new pipeline projects, quickly descended into an abyss of price declines, cancellations and COVID-19-related delays that had many wondering if their companies and jobs would survive, let alone return to anything resembling “business as usual.”

That said, the industry has survived, albeit a little warily after briefly seeing oil futures plunge to an unheard price of zero, and by most accounts there appears to be a light appearing at the end of the tunnel. In fact, in a recent analysis, Morgan Stanley went so far as to upgrade the 2021 outlook for midstream as “attractive,” in the wake of post-pandemic re-openings and the sector’s “self-help” measures. “Midstream stocks have been catalyzed by the prospect of a divided Congress (expectation of more benign tax and energy policy changes), coupled with the COVID-19 vaccine progress,” Morgan Stanley said in its 2021 MPLSs & Midstream Energy Infrastructure Outlook. “We see support for a sustained rally in midstream.” Other analysts agree, saying, in general, midstream should disproportionately recover as people return to more normal activities as the pandemic is brought under control and refined product demand recovers. Overall, the pipeline business appears to be relatively stable, all things considered, certainly in comparison to other energy sectors, such as exploration and production, which are more directly affected by volatility and oil and gas prices. Many midstream stocks have returned to early March, pre-coronavirus levels, led out of the gate by such major players in North America as Williams, Kinder, Enbridge and TC Energy. In another promising sign, some smaller companies such as Targa and Plain All American did even better than the larger companies.

That said, U.S. midstream companies reduced planned crude pipeline capacity expansions by more than 1.4 MMbpd through deferrals or scale-backs in the wake of the collapse in oil prices and effects to the COVID-19 pandemic. The bulk of these postponements involve projects that had been expected to be in service by the end of 2020. The following is a summary of some notable pipeline activity taking place across key global regions. Keep in mind, much of the downward trend, compared to 2020, reflects delays brought about by the pandemic. North America  Pipeline Miles Under Construction: 6,461 Pipeline Miles Planned: 18,796 Total: 25,276 Regionally, growth is expected to continue in the Gulf Coast for midstream, at least through 2025. This should increase investment, particularly when the COVID-19 adjustments taken by the sector are factored into consideration by financial institutions. Additionally, the Permian Basin and Bakken Shale areas will still provide good opportunities for midstream companies in 2021. With the 2.1-Bcf/d (59 MMcm/d) Permian Highway Pipeline going fully online in early 2021, and the 2-Bcf/d (57 MMcm/d) Whistler Pipeline still expected to go in-service in the third quarter, the results could play a key role in energizing midstream in that region. Permian producers should see significantly improved options with this eastbound expansion to the still burgeoning Texas Gulf Coast, where shipping at hubs remains reasonably attractive and should attract additional midstream projects. Meanwhile, in the second-largest field in the United States, Bakken producers still face pressure to delay bringing back much of the 500,000 bpd of their curbed output, following a court ruling in July that jeopardizes the operation of Energy Transfer LP’s Dakota Access Pipeline (DAPL), which ships most of the region’s oil. An appeals court has allowed DAPL to continue operating for now, but the threat of closure makes reversing cutbacks and drilling new wells too risky, executives and analysts say. DAPL links Bakken producers to Midwest and Gulf of Mexico customers, accounting for about 40% of the volumes transported to those regions. Rail transport, which is $3 to $6 a barrel more expensive, is expected to expand if the pipeline closes. Unfortunately, the midcontinent regions, the Marcellus and Utica, along with the SCOOP/STACK basin, will not fare as well. After scaling back by about 20% in 2020, based on Gulf Energy Information’s Energy Web Atlas, in part due to regulatory challenges posed to pipeline projects to the East Coast, much of the new year will likely consist on recovery efforts. Overall, it is difficult to estimate how spending in North America during 2021 will compare to 2020 – which was, hopefully, a year unlike any other we will ever experience. It is fair to say mid-2021 will be better than mid-2020. Additionally, there will be increased regulatory risk to projects and social opposition that, over the past few years, has increased its targeting to include banking institutions that finance pipeline projects. The related delays increase costs due to delays and court battles. A few, though certainly not all-inclusive, examples include the Northeast Supply Enhancement (NESE) postponed by Williams in May after a key permit was rejected, and delays to Mountain Valley Pipeline, which once again faces legal opposition in Virginia due to concerns about sedimentation and blasting that they say impact threatened and endangered species. In the ongoing saga of the Keystone XL pipeline, there was some encouraging news about the project’s prospects for 2021, though challenges remain, along with the possibility that President-elect Joe Biden will scrap an essential permit. Six U.S. union construction companies were awarded about $1.6 billion in contracts recently to build portions of the Keystone XL pipeline. The project’s owner, TC Energy, expects the work to get underway in 2021. Additionally, even as the pandemic-driven collapse subsides, there will likely be consolidation between larger diversified companies and smaller midstream operations. This is in addition to outright sales, such as the recent Devon Energy acquisition of Permian Basin peer WPX Energy for $2.56 billion and CenterPoint Energy’s sale of Miller Pipeline and Minnesota Limited to PowerTeam Services for $850 million. There will also be more mergers like the Husky Energy–Cenovus Energy agreement that created Canada’s No. 3 oil and gas producer. In Canada, which became the largest source of U.S. energy imports and the second-largest destination for U.S. energy exports behind only Mexico, production declines and payroll reductions largely mirrored those of the United States. On a favorable note, Canada’s Supreme Court made rulings in 2020 benefiting pipeline construction projects, including one that ended seven years of legal challenges to the Trans Mountain pipeline expansion. Now under construction, that project will triple the capacity of the 67-year-old pipeline from Alberta to the British Columbia coast. Completion is planned for late 2022. The Keystone XL and Line 3 pipelines would increase pipeline access for Canada, but Alberta producers would still be limited to refiners in the U.S. Midwest and Gulf Coast. The Trans Mountain expansion, however, could allow producers to access markets in California and Asia. Western Canadian oil producers have suffered from a shortage of export capacity from the region for much of the past decade, and the pandemic heightened problems, necessitating the shutdown of 1.2 MMbpd. Currently, there is about 700,000 bpd of surplus oil pipeline capacity out of Western Canada, based on comments by midstream firm Enbridge’s CEO Al Monaco during the company’s first-quarter 2020 earnings call. Construction has restarted on Coastal GasLink pipeline in the west, which will move gas from northeast British Columbia to the Pacific Coast, where the Royal Dutch Shell-led liquified natural gas (LNG) Canada export facility is under construction. Michels Canada won the contract from TC Energy to construct 162 miles (260 km) of the Keystone XL Pipeline Project in Alberta, Canada, which is expected to be completed in the spring of 2022.  The company will be directly responsible for hiring a projected 1,000 workers each year over the two-year construction period, between Oyen and Hardisty, Alberta, with special emphasis placed on hiring locally and giving priority to qualified local and indigenous businesses. South & Central America  Pipeline Miles Under Construction: 3,459 Pipeline Miles Planned: 14,001 Total: 17,460 The midstream sector in South America has been hit particularly hard by low prices and weak demand brought on by COVID-19 shutdowns and declining demand. Several projects have been pushed back until at least 2022, and some may never be built. Analysts report that pipeline companies in the region, as a rule, have been reducing capex by as much as one-third and slashing workforce totals, with an eye toward rebounding in late 2021. As was the case to start the year, the large countries of the region, particularly Brazil, Mexico and Argentina, which have been large producers and large importers of natural gas, each still face their own infrastructure challenges to meet domestic demand. Mexico continues to need more gas pipelines for electricity generation but was at least able to open the Texas-Tuxpan gas pipeline to meet the growing demand in the central and south-southeast regions of the country. Additionally, there was growing pre-pandemic interest in cross-border pipeline projects. There are currently 16 of these in the region: seven between Argentina and Chile; three between Bolivia and Argentina; two each between Argentina and Uruguay, with one connecting Bolivia with Brazil; one between Argentina and Brazil; and another between Colombia and Venezuela. Setbacks aside, Mexico’s energy administrator Sener expects two gas pipelines, totaling 760 miles (1,224 km), will be delivered by the middle of 2021. The first, the 280-mile (452-km) La Laguna-Aguascalientes, commissioned by the Federal Electricity Commission (CFE), will have a capacity of 1.29 Bcf/d (37 MMcm/d). The second is in the final phase of construction – the South Texas-Tuxpan South submarine pipeline – covering 480 miles (772 km), with a capacity of 2.6 Bcf/d (74 MMcm/d). The 381-mile (614-km) Samalayuca-Sasabe gas pipeline, also under construction, has a capacity of 472 MMcf/d (13 Bcm/d). The 232-mile (374-km) Villa de Reyes-Aguascaliente-Guadalajara with a capacity of 886 MMcf/d (25 Bcm/d) is under construction as well. Asia Pacific Pipeline Miles Under Construction: 13,776 Pipeline Miles Planned: 11,427 Total: 25,203 China remains the dominant force behind the region’s energy industry as the nation continues to work toward restructuring its state-owned energy assets and focus on natural gas as a power source. However, expansion of nuclear energy in China – as well as United Arab Emirates, Iran, Turkey and India – has led to a lowering of oil and gas demand that has helped slow construction of pipelines in China, with several projects canceled or delayed. Some large pipelines in China remain at below-capacity levels, which was amplified by the ramifications of the coronavirus lockdowns. This was especially true of oil pipelines. Still, to reduce dependence from Russian and African sources, China’s diversification efforts have led to pipeline projects in such locations as Myanmar and Central Asia, and massive investment, which is expected to continue. Central Asia has an abundance of oil and natural gas deposits, and the region accounts for about 4% of global energy deposits. The oil reserves in Central Asia and along the Caspian Sea coast amount to 17-33 bpd – with more unexploited deposits.

Two main pipelines from Central Asia to China, the Central Asia-China gas pipeline and Kazakhstan-China oil pipeline, are already in operation. The Central Asia-China Gas Pipeline (CAGP), spanning Turkmenistan, Uzbekistan and Kazakhstan, and crossing Xingjian at the border town of Horgos, transported 1.4 Tcf (40 Bcm) of natural gas when it was first built. It is connected to China’s second west-east gas pipeline, which starts from Horgos and ends in Hong Kong, stretching a total of 5,408 miles (8,704 km). This 685-mile (1,110-km) pipeline in China aims to help improve air quality in the region. This 685-mile (1,110-km) pipeline in China aims to help improve air quality in the region. China imported about 494 Bcf (18.4 Bcm) of natural gas through its first cross-border pipeline over the last two years. Given the nation’s plan to increase gas imports from Central Asia by five times, the Central Asia-China Pipeline’s capacity will expand up to 1.9-2.1 Tcf (55-60 Bcm) of gas per year. Upon the possible addition of what is now known as “Line D,” the Central Asia-China Gas Pipeline will have an annual deliverability of 3 Tcf (85 Bcm), the largest gas transmission system in Central Asia. The second of these pipelines, the Kazakhstan-China Oil Pipeline, is China’s first direct oil import pipeline that allows oil import from Central Asia. This pipeline flows from the Caspian shoreline, on Kazakhstan’s side, to China’s Xinjiang. The pipeline is jointly owned by China National Petroleum Corporation (CNPC) and the Kazakh state-owned oil company KazMunayGas. Africa Pipeline Miles Under Construction: 1,338 Pipeline Miles Planned: 15,466 Total: 16,854 A slow approvals system and frequent governmental flip-flops on projects has been at the crux of what has slowed development in the region for years, and 2020 was no exception. Abu Dhabi National Oil Company (ADNOC) said in June that a consortium of investors agreed to bring $10.1 billion in foreign direct investment for natural gas pipeline assets valued at $20.7 billion. Under the agreement, ADNOC will lease its interest in assets to ADNOC Gas Pipelines for 20 years in return for a volume-based tariff subject to a floor and a cap. Nigeria National Petroleum Corporation (NNPC) started construction of the biggest natural gas pipeline in the country’s history – a $2.8 billion, 384-mile (614-km) project from Ajaokuta to Kano. The 40-inch (1,016-mm) line will transport 3.5 MMscf/d (98,882 cm/d) from multiple gathering projects in southern Nigeria, resulting in the establishment of a connecting network between its eastern, western and northern regions. Tanzania and Kenya are constructing a 345-mile (558-km) gas pipeline between Tanzania’s Dar es Salaam and Tanga and on to Kenya’s coastal city of Mombasa. The project, which is being developed under a contract by China Petroleum Technology and Development Corp., will meet the estimated gas demand of 50 MMscf/d (1 MMcm/d) in the two countries. Demand is projected to rise to 150 MMscf/d (4 MMcm/d) by 2035. Additionally, Uganda discovered an estimated 6 billion barrels of oil in the Albertine rift basin in 2006, but production has been repeatedly snagged by disagreements with foreign oil companies over taxes and development strategy. The government now projects production will begin in early 2022. In December, landlocked Uganda granted environmental approval for a $3.5 billion pipeline to export crude oil from western fields to the Indian Ocean coast in Tanzania. If built, the 900-mile (1,445-km) pipeline will run from fields co-owned by France’s Total and China’s CNOOC and would cross sensitive ecological systems including wildlife-rich areas, rivers and swampland that are catchments for Lake Victoria. Russia & CIS Pipeline Miles Under Construction: 8,538 Pipeline Miles Planned: 7,340 Total: 15,878 The biggest news for the region continues to revolve around the politically charged Nord Stream 2 gas pipeline. As of late-December, Russia had resumed construction of the 765-mile (1,230-km) pipeline to Germany, laying pipes after a one-year hiatus prompted by U.S. sanctions, according to the pipeline operator. Swiss-Dutch company Allseas suspended its work in December 2019 following the threat of sanctions from Washington, D.C., leaving Russia to find other resources to construct the project, which is designed to double the 1.9-Tcf (55-Bcm) annual gas capacity of the existing Nord Stream pipeline. The two pipelines, which bypass Ukraine, will have the capacity to pump more than half of Russia’s total gas exports to Europe. Rows between Moscow and Kyiv over gas supplies led to the interruption of Russian flows to Europe in previous decades. Russia also agreed with frequent foe Belarus to a deal on gas prices for 2021, easing tensions between the two former Soviet countries. The price this year was $127 per 6,290 US bbl (1,000 cubic meters). Separately, operations have started on the middle portion of the 685-mile (1,110-km) China-Russia East natural gas pipeline, allowing natural gas from the Power of Siberia system in Russia to be transmitted to the smog-prone Beijing-Tianjin-Hebei region in northern China. Middle East Pipeline Miles Under Construction: 1,041 Pipeline Miles Planned: 3,244 Total: 4,285 Even after the pandemic was in full swing, United Arab Emirates and Israel discussed joining forces on energy-related opportunities, including natural gas exports to Europe, and signed an agreement on Sept. 15 to establish diplomatic relations in the wake of what Israel’s Energy Minister Yuval Steinitz called a “historic opportunity.” In addition to exports to Europe, the two nations’ talks pointed toward the possibility of linked power grids. Separately, Egypt, Israel, Greece, Cyprus, Italy and Jordan signed a charter to form the East Mediterranean Gas Forum (EMGF), which establishes a united front by the rivals of Turkey, a nation that has been locked in a dispute with European Union (EU) members Cyprus and Greece over drilling rights in the region. Israel is significantly increasing the amount of natural gas it plans to export via the EMED Pipeline to Egypt, based on data from Israeli energy companies. Partners in Israel’s Leviathan and Tamar offshore gas fields agreed to sell $15 billion worth of gas to a customer in Egypt under the deal. Texas-based Noble Energy, Israel’s Delek Drilling and Ratio Oil own Leviathan. Noble, Delek Drilling, Isramco and Tamar Petroleum are leading partners in the Tamar field. Noble and Delek Drilling have also partnered with Egyptian East Gas Co. in a venture called EMED, which bought the subsea EMG pipeline to carry the gas. Additionally, Greece, Cyprus and Israel are pushing toward building a 1,180-mile (1,900-km) subsea pipeline to carry natural gas from the eastern Mediterranean’s rapidly developing gas fields to Europe. Although Turkey opposes the project, the countries aim to reach a final investment decision by 2022 and have the pipeline completed by 2025 to help Europe diversify its energy resources. Western Europe/EU Pipeline Miles Under Construction: 3,863 Pipeline Miles Planned: 4,555 Total: 8,418 Europe remains a key battleground for global natural gas and LNG market share, and has shown a serious commitment to hydrogen gas pipeline networks in an ongoing push to clean energy. Over the next decade, Germany plans to create the longest hydrogen transmission pipeline network in the world. In 2020, the German Federal Government assigned $10 billion, under its National Hydrogen Strategy policy, toward kick-starting an expansion of electrolysis capacity for large-scale hydrogen production. The planned nationwide hydrogen 3,666-mile (5,900-km) pipeline network is designed for large-scale transmission of hydrogen throughout Germany and should be completed by 2030. Meanwhile, developers of the Trans Adriatic Pipeline (TAP) have started feasibility studies on blending hydrogen with the natural gas the pipeline will bring in from Azerbaijan, TAP said. TAP is the final leg of a $40 billion project named the Southern Gas Corridor, which will carry 353 Bcf (10 Bcm) of gas per year from the giant Shah Deniz field into Europe. The pipeline, already commercially operative, is set to start pumping its first gas into Italy at the end of 2020.

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6:22:00 PM | 0 comments

Hot Tapping (Pressure Tapping) and Freezing A. Keith Escoe, in Piping and Pipelines Assessment Guide, 2006

Test Pressure and Temperature Per the API RP 2201, conduct a hydrostatic test at a pressure at least equal to the operating pressure of the piping to be tapped, but not exceeding the present internal pressure by more than approximately 10% in order to avoid possible internal collapse of the pipe wall. If there exist conditions that could cause collapse of the pipe wall, the test pressure can be reduced. If a hydrostatic test is not practical, then a pneumatic test may be performed, using the common precautions. Note that header walls can collapse during testing if insufficient internal operating pressure or excessive external hydrostatic pressure is applied. This is especially true for large diameter piping and pipelines. The test pressure can be limited if necessary to prevent shell buckling because of differential external pressure between the outside and inside pipe wall being hot tapped. This is accomplished by either a reduction in the test pressure from that calculated using the applicable code rules or an increase in the pipe internal pressure. Shown in Figure 7-3 is a hot tap nozzle welded to pipe with external load (hydrostatic test pressure). It shows the two different configurations for the nozzle connection—a welded fitting or a saddle and a full encirclement sleeve. Shown in the weld configurations, the hydrostatic test pressure is contained within the confines of the inside of the nozzle wall. If the hydrostatic test water leaks through one of the welds, then that would be a hydrostatic test failure. A more graphic detail of the typical 90° nozzle connection is shown in Figure 7-4.

Figure 7-3. Hot tap nozzle welded to a pipe with external load on the pipe wall during hydrostatic test.

Figure 7-4. Typical 90° nozzle connection. The maximum pressure required to buckle the shell wall consists of a curved plate clamped at the edges. This situation is for a saddle or reinforcing pad assembly that does not encompass the entire circumference of the pipe. This problem of elastic stability was first solved by E. I. Nicolai in St. Petersburg in 1918, cited in Timoshenko and Gere, Theory of Elastic Stability [Reference 3]. The buckling pressure is in the following form:

This particular case is in Roark's 7th edition, Table 15.2 Case 21 [Reference 4]. Curved panels under uniform loading were a topic of great interest in Russia, where it snows heavily during the blizzard winters. As the story goes, whenever snow loads would build up, a curved roof sometimes would collapse. Consequently, interest to solve the problem stimulated a formal analytical solution, shown above. As seen in Figure 7-3, the hot tap connection can be either a saddle or full encirclement sleeve. The latter type is shown in more detail in Figure 7-5.

Figure 7-5. A full encirclement sleeve for hot tap installation. Courtesy of ExxonMobil, Inc. The hydrostatic test pressure is assessed as in the ASME Section VIII Division 1 code for external pressure on a cylindrical shell. The assessment uses the A and B values in the ASME Section II Part D curves for the material considered. Before any component is welded, be it a saddle, reinforcing pad, or a full encirclement sleeve, an NDE such as UT needs to be performed to certify that the remaining wall thickness on the pipe is substantial enough to have hot work performed. If the pipe has an LTA (see Chapter 3) and a sleeve is to be welded on, the pipe is no longer of uniform thickness, and the assessment in the ASME Section VIII Division 1 for external pressure is not valid. For a pipe with an LTA, a buckling assessment using finite element is required to find the critical buckling pressure. Normally, it is accepted practice not to perform hot taps close to corroded regions to avoid this situation; however, this event cannot always be avoided. Typical nonperpendicular nozzle hot tap connections used for pipe sizes 3 in. NPS and smaller are shown in Figure 7-6.

Figure 7-6. Typical hot tap installation for a nonperpendicular installation (e.g., an elbow). Courtesy of ExxonMobil, Inc. To facilitate drilling and cutting, guide plates are required for nozzles—both flanged and threaded—when attached to elbows or when installed at angles other than in the perpendicular direction. Typical nonperpendicular nozzle hot tap connections for pipe sizes 4 in. NPS and larger are shown in Figure 7-7.

Figure 7-7. Typical nonperpendicular nozzle hot tap connections for pipe sizes 4 in. NPS and larger. The angle beam shown is to allow the drill with the cutter to maintain a common line of drilling to ensure a proper connection. Courtesy of ExxonMobil, Inc. The guide angle sizes shown in Figure 7-7 are standard AISC (American Society of Steel Construction—see Chapter 6) structural shapes. If required to make angle surface perpendicular to the axis of the pilot drill, one leg of the angle may have to be trimmed. Guide angles are not installed for cutter or drill sizes less than 2 in. OD. These guide angles provide the means to drill straight into an elbow. Without them, a worker could drill at an angle resulting in an improper fit-up. Bolted-on fittings should be used in services where bolted-on fittings should be considered (e.g., caustic or piping requiring PWHT). When heat is applied to caustic, it becomes much more corrosive. Caustic becomes highly corrosive at high temperatures and can either cause severe corrosion damage or even eat through the pipe. Also, bolted-on fittings are used where the material is non-weldable (e.g., concrete) or difficult to weld (e.g., cast iron). The use of bolted-on fittings is limited by design to piping normally less than 12 in. (400 mm) in diameter. These mechanical clamps are normally fabricated of carbon steel and use a rubber compression joint to seal against the pressure. This type of hot tap fitting is shown in Figure 7-8. Various other connections acceptable for hot taps are shown in Figure 7-9.

Figure 7-8. Typical bolt-on hot tap fitting. Courtesy of ExxonMobil, Inc.

Figure 7-9. Various connections used for welded-on hot taps. Hot tap connections are normally summarized on a computer spread sheet, as shown in Figure 7-10. The Type 1 is the full encirclement saddle, which is permitted in all cases. This type is preferred if vibration is possible. The Type 2, the full encirclement sleeve, is required when vibration will occur and is used when a Type 1 connection is not available; otherwise, it is permitted in all cases. The Type 3 is the split tee, which is used for hot tap installation with a standard flange or lock-o-ring flange. This type is more expensive than the Type 1 or 2. The Type 4 is the welding outlet. It is permitted only when supplied by a reputable manufacturer. The Type 5 is the circular reinforcing pad and is permitted in all cases except when there are large amounts of vibration. The full encirclement sleeve is preferred when the branch is greater than 70% of the header size. The Type 6 connection is the saddle, which has the same applications as the Type 5 except that it is preferred for high levels of vibration services with small branch connections. The Type 7 is the contour insert, which has the same application as the Type 6 connection except that it is preferred and recommended with 100% radiography. A typical hot tap calculation is shown in spreadsheet form in Figure 7-10.

Figure 7-10. Typical hot tap calculation on a spreadsheet. Summary Procedures The engineer of the proponent organization fills out the spreadsheet, and it is checked by a unit engineer as well as inspection and operations personnel before issued to the contractor. The steps required for implementing a hot tap and stoppling vary with each company. The reader will notice that there are three solutions to the hydro test of the hot tap connection. If a saddle or reinforcing pad is utilized, the Nicolai solution of Eq. 7-1 (Roark's 7th edition, Table 15.2 Case 21 [Reference 4]) is applied. If the hot tap connection is a full encirclement sleeve, then the ASME Section VIII Division 1 rules for external pressure are applied. However, as mentioned previously, if the full encirclement sleeve covers an LTA, then a buckling assessment should be performed. This assessment can be done with a linear elastic finite element model for the differential pressure between the pipe internal pressure and the applied external test pressure. Some companies avoid the finite element assessment by not allowing a hot tap or stopple close to an LTA; however, this event cannot always be avoided. During welding the inner temperature of the pipe wall can rise to 19,000°F (10,400°C). This temperature can vary, depending on the wall thickness of the pipe, welding amperage, and welding technique. Temperatures of this magnitude can result in metallurgical changes in steels. Also the contents inside the pipe can be affected by such temperatures. Materials that become unstable with heat should not be subject to hot tapping. Oxidizers (e.g., oxygen and chlorine) can cause explosions with mixtures of air and fuel. Hydrogen, hydrogen mixtures, and caustic can result in cracking of the pipe in the weld metal or heat-affected zone. Hot tapping on high purity ethylene can result in exposure of the chemical to high temperatures, and violent decomposition can occur. Tests have been performed that show that for clean systems, pressures as high as 1200 psig (8.0 MPag) can be tolerated without decomposition. However, experience indicates that pressures of the magnitude of 300 psig (2.0 MPag) are more reliable as a safe limit for operating equipment. Piping that contains pure acetylene should not be hot tapped. The limiting pressure for decomposition depends on the temperature of the acetylene. However, with temperatures experienced during welding, pressures as low as 15 psig can be sufficient for decomposition. Vinyl acetylene has been shown to decompose at 10 psig pressure at moderate temperature. Butadiene is normally more stable than ethylene; applying the same restrictions for ethylene to butadiene can avoid explosive decomposition. Butadiene in the presence of oxygen reacts to form a peroxide polymer that can decompose explosively. One must prevent the forming of butadiene peroxide, even in small quantities, because of its highly unstable nature. During hot tapping, the cutting machine must be purged of all air to prevent the formation of butadiene peroxide in the hot tapping equipment. Any line that contains butadiene peroxide should not be hot tapped. When hot tapping piping contains hydrogen, hydrogen attack can occur. Hydrogen attack is a function of the hydrogen partial pressure, temperature, time, and material of construction. It can take the form of internal decarburization and fissuring, hydrogen blistering, and dissolved hydrogen leading to embrittlement. Allowable hydrogen partial pressures are based on the API RP 941, Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants [Reference 2]. For hot tapping, the piping should be operating at at least 100 psi (0.7 MPag) below the appropriate Nelson curve. Typically, low hydrogen welding electrodes are used for hydrogen service. The area hot tapped should be inspected by magnetic particle or liquid penetrant approximately 2 days after welding. To help distribute the residual stress in the weld connection, full encirclement fittings are recommended for hydrogen service. Shown in Table 7-1 are typical problematic processes for hot tapping. This table is a general guideline for hot tapping piping where one should use caution. Table 7-1. Hot Tapping Selected Process Fluids

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