Four companies have teamed up to create a new manufacturer of LNG processing equipment to serve Russia’s budding liquefaction sector. The head of Germany’s Linde and counterparts at Russian firms Power Machines, Salavatneftemash and Gazprom signed an agreement of intent at the St Petersburg International Economic Forum on June 17.
“It is planned to prepare a feasibility study and a business plan to identify the most efficient form of partnership, including a possible joint venture, by the end of 2016,” Gazprom said in a statement. “The feasibility study and business plan will take into account the technological demand for and the competitiveness of such equipment in Russia,” the statement continued. “Russian-made components will be used in the manufacturing process to the maximum extent possible.”
Munich-headquartered Linde already has a presence across Russia, producing industrial, food-grade, medical and special gases for the domestic market, while also working on LNG projects in Norway, Malaysia and Australia.
In January, Gazprom selected Linde as the licensor for its cryogenic gas separation technology to be installed at the state-owned firm’s Amur gas-processing plant in Russia’s Far East.
Power Machines manufactures turbines for power plants in Asia and Russia, co-operating with state-controlled Rushydro. Salavatneftemash is based in central Russia and is one of the country’s largest producers of oil and gas refinery equipment, including truck pipeline infrastructure. The decision to form the quartet is part of Russia’s broader plans to quintuple annual LNG production to 53.6 million tonnes by 2035.
Novatek also struck a number of deals at the St Petersburg forum. The company announced partnerships with Saipem, Nuovo Pignone and Linde at the meeting, in addition to a co-operation agreement with Sberbank and the government of the Leningrad region. The agreement with Nuovo Pignone included a 25-year services agreement on the Yamal LNG plant. The company committed to ensuring safe operations in the harsh environment of the north and included provisions for the training of Russian specialists.
Nuovo Pignone signed a contract in 2013 on supplying turbomachinery equipment, produced and tested in Italy, for the three trains of the Yamal LNG project.
Further adding to the various deals in St Petersburg, Gazprom announced an agreement with Russian Railways, Sinara Group and Transmashholding on June 17 on the use of natural gas in transportation. The deal covered the use of gas in “railway and motor transport, mitigating environmental impacts, facilitating NGV market growth, increasing domestic gas consumption, and fostering the national machine building industry”.
Gazprom committed to the construction of refuelling facilities in sites approved by Russian Railways and the provision of LNG to railway rolling stock. Russian Railways, meanwhile, said it would adapt various depots to accommodate the facilities and would provide training for engineers, technicians and train crews for gas-powered locomotives.
Edited by Joe Murphy
Engie gears up for new Norway wildcat
Engie E&P Norge has been cleared to drill a new exploratory well, 36/7-4, in Production Licence 636 offshore Norway, by the Norwegian Petroleum Directorate (NPD).
The wildcat will be drilled approximately 55 km southwest of Floro and about 10 km northwest of the Gjoa field, which is one of the company’s flagship projects.
The wildcat area consists of a part of petroleum Block 36/7, which is operated by Engie E&P, and partnered by Idemitsu Petroleum Norge, Wellesley Petroleum and Tullow Oil Norge.
Engie E&P intends to use the Transocean Arctic drillship for the work as soon as the rig completes the drilling of another wildcat, 31/7-1 A, on behalf of Faroe Petroleum Norge in PL740.
The company has reported higher output from the Gjoa development, its first operated production on the Norwegian Continental Shelf (NCS).
The gas field, first discovered in 1989, sits about 60 km west of Floro and contains an estimated 40 billion cubic metres of reserves.
“Gjoa was originally designed to export 17 million cubic metres per day of gas. That we are currently producing 20 mcm per day of gas – 17.5% more than estimated – is a great achievement,” said Hilde Adland, head of operations.
Engie E&P Norge acquired a 30% interest in the field in 2003, with the authorities approving the development in 2007. This cleared the way for one of the largest offshore projects in Norway since Snohvit, in which the company is also a stakeholder.
Engie E&P also produces light oil and condensate from the Gudrun field in the North Sea, which commenced output in 2014, and the Njord field in the Norwegian Sea
Edited by Ryan Stevenson
OneSubsea wins Zohr EPC work
OneSubsea has won an engineering, procurement and construction (EPC) contract worth US$170 million for subsea work on the Zohr field, offshore Egypt. The Schlumberger unit announced the award from Petrobel, a joint venture of Eni and Egyptian General Petroleum Corp. (EGPC), on June 20.
“Zohr is one of the largest gas fields discovered in the Mediterranean Sea to date, and is also the world’s second longest step-out, a distance greater than 150 km. This step-out will be enabled by OneSubsea controls systems with fibre-optic communications technology,” said OneSubsea’s president, Mike Garding. “Our supplier-led approach to the field development, coupled with our FasTrac programme capability, and our integrated offering that includes flow assurance, subsea production system and landing string capabilities, will help Petrobel meet their first gas commitment.”
OneSubsea worked on Zohr’s front-end engineering and design (FEED). The statement said the system would have to handle high gas volumes, while taking into account reservoir characteristics and subsea equipment specifications.
The contract covers six horizontal SpoolTree subsea trees, it said, with intervention and workover control systems, landing string, tie-in, high-integrity pressure protection system, topside and subsea controls and distribution, water detection and salinity monitoring provided by the AquaWatcher water analysis sensor, and installation and commissioning services.
OneSubsea’s FasTrac programme is intended to allow a fast and flexible means by which to configure a production system to meet customers’ needs.
Aker Solutions announced, in a statement on June 6, that it had won work on the umbilicals system at Zohr. The award was worth US$122.3 million, it said, and would cover the delivery of 180 km of steel tube umbilicals, which would connect the development to an offshore control platform. Aker’s umbilicals are due to be delivered by mid-2017. The project is the company’s largest ever of umbilicals.
The Zohr field was found in August 2015, on the Shorouk concession, and Eni intends to bring it into production by the end of 2017. The company began appraisal drilling at the start of 2016 and took the final investment decision (FID) in February.
Edited by Ed Reed
CGG completes Gabonese pre-salt shoot
Early results from state-of-the-art seismic covering the acreage offered in Gabon’s 11th deepwater licensing round indicates numerous pre-salt prospects, CGG said last week.
In a June 1 statement, the Paris-headquartered company said initial seismic imaging results suggest the existence of key intervals of a pre-salt petroleum system – namely syn-rift and sag sequences below the salt – and “many exciting prospects” that extend beyond the borders of the survey.
CGG claims that understanding of the area’s geology is being revolutionised as a result of its survey, which captured more details below the salt than have previously been seen. This should provide “dramatic” improvements to subsalt imaging in the final dataset.
Covering 25,000 square km of newly available and licensed blocks in Gabon’s South Basin, the multi-client 3-D shoot aimed to “image potential prospective structures at base salt level without compromising the shallower post-salt image quality”, CGG said.
An onboard preliminary ultra-fast-track dataset seen by a major oil company interpreter was described as “way beyond expectations”, the statement noted.
The survey’s fast-track pre-stack time-migrated (PSTM) dataset is already available, as is sample pre-stack depth reverse time-migrated (RTM) data for one area, with the final RTM for the complete area due this summer.
CGG said its fast-track PSTM showed “clear uplift over the existing data” with fast-track pre-stack depth migrated data highlighting the full benefits of advanced velocity modelling and depth-migrated modern broadband 3-D seismic.
The dataset provides insights into the area’s subsurface, it said, and this will be further improved following the acquisition of additional data covering the more complex geology of the area’s southeast. This includes the F14 block and, adjacent to the border with Republic of Congo (Brazzaville), the F15 block, CGG said.
This data forms the centrepiece of an integrated geoscience project that will allow analysis of the basin’s deep structure and its key wells in order to reduce exploration risks, the statement added.
Encouraged by recent Gabonese pre-salt discoveries, including Diaman, Leopard, Ruche and Tortue, the bid deadline for Gabon’s 11th deepwater licensing round closed on May 31, having attracted “considerable interest” from international companies and minnows alike, CGG said.
Edited by Ed Reed
YPF plans efficiency drive
Argentina’s YPF is pushing ahead on projects to improve efficiency for cutting shale drilling costs, increasing heavy crude output and developing a recent conventional gas find.
“We have to find ways to be more competitive, efficient and innovative,” YPF chairman Miguel Gutierrez said in a statement during a visit to the provinces of Mendoza, Neuquen, Santa Cruz and Tierra del Fuego.
In Neuquen Province, the state-run company will this year bring on line infrastructure to raise output from the giant Vaca Muerta shale play, whilst also reducing drilling and completion costs. This includes a 50,000 barrel per day crude-processing plant that can be expanded to 63,000 bpd, the company said.
The plant is being built in Anelo, a town at the heart of the Vaca Muerta oil window where YPF is working with Chevron on the country’s largest shale development. They are producing 50,000 barrels of oil equivalent per day from the Loma Campana block.
Also in Anelo, YPF is building a sand treatment plant with capacity to process 140 metric tonnes per hour. The facility will provide 100% of the natural sand YPF needs for fracking, and will be equipped to start producing resin-coated proppant in 2017. This will save the companies 50% on the cost of the product by replacing imports, and will make it possible for it to sell the surplus proppant to competitors.
In Mendoza, YPF will fire up a US$62 million oil treatment plant on its Malargue block, replacing one that burned down in 2014. The plant will allow it to process more heavy crude, which has surged 46% to 1,300 bpd on its Llancanelo block over the past year, Gutierrez said. YPF wants “to provide more scale for this development,” the company said.
Further south in Santa Cruz, the company is building a new water-injection plant to cut costs in secondary recovery projects, whilst it is also planning to develop a new conventional gas project.
The company found conventional gas reserves on its Los Perales-Las Mesetas block in 2014 after drilling deeper than the maturing formations that are currently producing about 15,000 bpd of oil and 980,000 cubic metres per day of gas. The find will add 370 bpd of crude and 200,000 cubic metres per day of gas.
The projects come as the company seeks to sustain oil and gas production this year at 2015 levels even as it cuts capital expenditure by 20% to 25% in response to low global oil prices and the impact of an economic recession on energy demand in Argentina.
YPF produces 44% of the country’s 530,000 bpd of oil and 30% of its 120 mcm per day of gas.
Edited by Ryan Stevenson
Pemex seeks partners for Trion deepwater project
Pemex last week announced its first farm-out for deepwater acreage in the Gulf of Mexico. The terms of the contract have not yet been revealed, with bidding guidelines due to be published in July.
The company and the Energy Ministry have approved a process to migrate the contract to develop the offshore Trion block from one that would see Pemex work on the project alone to a joint operating agreement (JOA) with one or multiple partners.
The state-run Mexican company said it wanted to establish a joint venture with between one and three partners for the project, which requires investment of around US$11 billion over the next 15 years.
Mexican Energy Minister Pedro Joaquin Coldwell said a farm-in process would expedite development, as companies that partnered with Pemex would provide investment and technology and thereby reduce the amount of capex necessary from the overstretched national oil company (NOC). Pemex is undergoing a fiscal retrenchment, as it looks to become a more nimble and effective player in Mexico’s newly liberalised energy sector.
Pemex has been developing Trion since 2012. The block is located in water depths of around 2,500 metres in the Perdido area of the Gulf of Mexico, some 200 km off the Mexican coast. It has estimated reserves of approximately 485 million barrels of oil equivalent.
Though the exact terms of the JOA will not be published until next month, it is anticipated they will reflect those on offer in Mexico’s deepwater bid round, which is due to be held in December and which will involve ten blocks. Trion is adjacent to several of the blocks on offer.
The farm-out opportunity will also be tendered via an international bidding procedure, in line with the terms on offer by the National Hydrocarbons Commission (CNH) for the December auction. Technical information on Trion has been made available by the National Centre of Hydrocarbons Information (CNIH), a division of the upstream regulator.
The establishment of partnerships between Pemex and international oil companies (IOCs) is viewed as critical to Mexico reviving its oil production. Output is currently down by over 1 million barrels per day from the 3.4 million bpd recorded in 2004, as shallow-water fields mature. Production from deepwater fields is viewed as being the best way to offset declines at fields closer to shore.
Chevron, ExxonMobil, Repsol, Royal Dutch Shell, Statoil and Total have all been tipped as potential participants in the December deepwater auction. They could also be interested in the Trion farm-in opportunity.
Edited by Ryan Stevenson
Eni cleared for Barents Sea drilling
Eni Norge has received clearance from the Norwegian Petroleum Safety Authority (PSA) for an exploration well at PL 226 in the Barents Sea.
The well, designated 7222/1-1, will target the Aurelia prospect at water depths of around 424 metres. Drilling will be performed by Saipem’s Scarabeo 8 semisubmersible drilling rig, which is designed according to the Moss CS-50MkII template. The rig is capable of operating in heavy winter conditions, and can reach depths of between 70-3,050 metres.
Eni holds a 60% operative stake at PL 226 alongside partners Edison and E.ON with 20% interest each.
Work is expected to last at least 58 days, with previous reports suggesting an 82-day operation if Eni makes a discovery.
The Italian major marked a milestone for the region in March when it launched Goliat, the first producing oilfield in the Norwegian Barents Sea.
Eni will have gained expertise by negotiating the harsh Arctic climate at much-delayed Goliat, which is expected to peak at 100,000 barrel per day output from 12 production wells.
Norway’s Barents Sea, the northernmost part of the country’s continental shelf, is estimated to hold 7.6 billion barrels of oil equivalent of undiscovered hydrocarbon potential.
Explorers have made four discoveries of more than 100 million boe in the Norwegian Barents over the last five years, and roughly 100 wells have been drilled at its basins since 1980.
Oslo had high hopes for the Barents after Statoil launched its Snohvit gas field in October 2007, but exploration has slowed with the collapse in crude prices.
Explorers have become increasingly sceptical at the high costs of production and technical challenges prevalent in the world’s northernmost reaches.
Oslo suffered a setback in April when Royal Dutch Shell announced it would withdraw its application for Barents licences offered in the 23rd licensing round.
Norway needs to unlock fresh reserves to replace output, which has halved since 2000. Oslo hopes to regain some momentum with the latest awards, which included acreage in the southeast previously inaccessible because of a long-running maritime dispute with Russia.
On May 18, Oslo announced it had awarded three licences in the south-eastern region. In total, Norway awarded ten licences to 13 firms, with Statoil and Lundin securing the most blocks.
Edited by Ryan Stevenson
ANT Telecom says the Internet of Things can only get better
The practical application of connectivity tools is all around us. Immersive technology is connecting factory machines to alert engineers when a unit malfunctions. In healthcare settings, smart technology monitors refrigeration to keep high-value medicines at regulated temperatures - and informs healthcare professionals when potential problems arise. In hazardous remote environments or manufacturing plants, intuitive technologies are being connected to Alarm Messaging Applications to protect lone workers, accelerate response and mitigate risk.
These applications are long established and use simple and cost-effective everyday technologies. They don’t require sophisticated IoT architecture, painful implementation programmes or significant investment. And they work.
Make no mistake, IoT is an exciting prospect that will transform the way we work. Its central promise – ubiquitous connectivity – will undoubtedly deliver major gains. But for businesses seeking to safeguard their workers, improve productivity and find greater operational efficiencies, connectivity is not the issue.
The challenge for companies is to move beyond connectivity and focus on the much more critical aspect of escalation. Whether you’re using technology to improve lone worker protection, maintain business continuity or alert mechanical failure, the most effective systems are those that are built to include robust and responsive processes for escalation management and audit capability. Connectivity is only the starting point.
The development of intuitive systems to protect operations and human resources does not require a technological revolution or wholesale investment in the Internet of Things. But it does require taking a considered, pragmatic and holistic approach to designing the most appropriate solution to suit individual business needs. The most successful organisations will be those that work with an experienced and trusted communications partner to help them join up the dots. In a world of connectivity, that’s one connection that really is worth making.
Hilong bags Indonesian service contract
Hilong Petroleum Offshore Engineering has won its first offshore services contract outside Chinese waters, sealing a deal to install jackets at a gas development in Indonesia.
Timas Suplindo awarded the contract – which will see Hilong use the Hilong 106 pipe-laying derrick barge at the HCML Madura MDA-MBH project – earlier this month, Shanghai-headquartered parent Hilong Group said on June 17. The group added that the deal was very significant, as it laid a “firm foundation” for further development of its offshore engineering services arm, in addition to being the subsidiary’s first offshore lifting operation contract.
Most of the work will involve lifting and upending jackets underwater in the Madura Strait, off Java, with an expected start date of mid-November and completion anticipated by the end of February 2017, the statement said.
Hilong Group’s vice president and Hilong general manager, Xiao Long, attributed the award of the contract to the service provider’s “innovative transportation and installation technology”, as well as the “inclusive construction solutions” offered by Hilong 106.
Madura MDA and MBH are two of seven shallow-water gas and condensate fields with significant exploration potential within the East Java Basin, covering a total area of 2,805 square km.
The development project is a joint venture between field operator CNOOC Ltd and Canada’s Husky Energy, each with 40%, and Indonesia’s Samudra Energy with the remaining 20%.
In April, Husky said that when the project was fully ramped up in 2018-19 it would provide combined net sales volumes from the BD, MDA-MBH and MDK fields of approximately 100 million cubic feet (2.83 million cubic metres) per day of gas and 2,400 barrels per day of associated liquids.
Edited by Andrew Kemp
HHI clinches deal for two new LNG carriers
Shipbuilder Hyundai Heavy Industries (HHI) has clinched a deal to build two LNG carriers, industry sources said on June 2. The deal is estimated to be worth US$400 million. The sources said the South Korean-based company had won the order from SK E&S, a South Korean LNG importer, to build the two vessels, which can each carry 180,000 cubic metres of LNG. The vessels will be built at HHI’s shipyard in Ulsan and are scheduled to be delivered at the start of the first half of 2019.
International Shipping News said the vessels, designed according to the new IGC standards published in 2016, would be equipped with GTT’s Mark III Flex membrane technology. The report said Mark III Flex was well-suited for the highly efficient XDF propulsion system installed on SK Shipping’s LNG carriers, as the technology offers a high level of insulation performance.
HHI and its local rivals such as Samsung Heavy Industries (SHI) have been struggling to win new orders amid a protracted slump in the global shipbuilding sector, which has been hit by lower oil prices. South Korea is the world’s second largest LNG importer after Japan, but LNG demand growth in the Asia-Pacific region has declined over the past two years. The Korea Times said that in the first quarter of the year, HHI’s new orders had passed US$1.74 billion, down from US$3.02 billion a year earlier.
HHI recently received approval from its creditors to implement a new self-structuring plan. The company claims that under the plan it can save or raise up to 3.5 trillion won (US$2.94 billion). South Korea’s Yonhap news agency said that under the shipbuilder’s plans, which have been temporarily approved by its creditors, led by KEB-Hana Bank, it would cut stock holdings, sell non-core assets and cut its workforce. This should reduce its debt-to-equity ratio to below 100% by 2018. Maeil Business News Korea said the LNG carriers would be transporting LNG supplies from US shale supplies in which SK has been working.
Edited by Ed Reed
CUCBM to use drones in remote surveys
State-run CBM developer China United Coalbed Methane Corp. (CUCBM) is reportedly planning to use small aerial drones to collect survey data in remote and difficult terrain.
Drones, also known as unmanned aerial vehicles, are becoming commonplace in China for numerous commercial uses, including delivering parcels.
The use of drones is much more liberal in China than in most other countries such as the US where restrictions or bans are in force. Drones weighing less than 7 kg do not need a licence from the Civil Aviation Authority of China, said E&P magazine.
CUCBM is now controlled by national oil company (NOC) China National Offshore Oil Corp. (CNOOC) and is exploring and developing numerous potential CBM blocks in northern China, often in remote mountainous terrain.
Initially, drones will be deployed by the firm to collect data from wells already sunk in blocks in difficult terrain, Interfax China said. Despite having confirmed reserves of 36 trillion cubic metres, growth in CBM production has been slow.
The National Energy Administration (NEA) has set a national production target of 30 billion cubic metres per year for 2020. The sector produced 18 bcm in 2015 but less than 50% was put to use, and the rest was allowed to escape into the atmosphere, the NEA said.
CUCBM operates or has stakes in blocks in Shanxi Province, Inner Mongolia and the rugged northwest Xinjiang region.
Meanwhile, the Ministry of Environmental Protection has authorised the resumption of three coal-to-gas (CTG) projects that had been suspended for over a year over concerns about their environmental impact and commercial viability, Fenwei Energy said.
The three projects, with a total capacity target of 4 bcm per year, are in the coal-producing regions of Shanxi, Xinjiang and Inner Mongolia.
“China has pledged to reduce its coal dependence,” Fenwei said. “However, policymakers are also trying to secure a soft landing for a sector that employs more than 5 million people, and coal-to-gas has the potential to be a new opportunity for mining firms.”
Edited by Andrew Kemp
NOV to buy Trican’s well completion tools division
Houston-based National Oilwell Varco (NOV) has unexpectedly agreed to buy Trican Well Service’s well completion tools business for almost US$41 million in cash and stock.
Trican designs and sells patented downhole tools for multi-stage fracturing and multi-zone completions in North America and select international markets, including Russia and Norway.
The purchase positions NOV to expand its onshore presence and could be seen as evidence of the appeal of the unconventional market.
It is a “wonderfully strategic deal”, said investment banking firm Tudor, Pickering, Holt & Co. (TPH). “Via its wellbore technologies business – drilling fluids, drill pipe, downhole tools, drill bits – NOV touches more wellbores during the well construction process than any other company,” said TPH.
“We’d argue that NOV’s Completion & Production Solutions product offering has been more surface/subsea-centric vs. downhole-oriented until now,” it added.
“This transaction represents an exciting step for NOV in expanding the breadth of our completion and production related product offerings,” said NOV’s chairman, president and CEO, Clay Williams.
“The transaction allows NOV to leverage our best-in-class manufacturing and global supply chain to expand sales into new markets and meet our customers’ demands for cost-effective, innovative and high quality completion tools,” he added.
NOV, a rig manufacturer and oilfield services provider, will continue to develop additional downhole completion technology to help customers reduce their cost of supply, Williams said. The company will retain Trican’s team.
Trican, an oilfield services company based in Calgary, said it would use the proceeds to reduce its outstanding debt. Closing of the transaction is expected on or around June 30, 2016
The deal comes as a boost to NOV, which has recently announced job cuts and closures.
“We have closed or are closing 200 facilities since the downturn began, and we reduced our workforce by nearly 6,000 employees during the first quarter of 2016,” said Williams on an analyst call in April.
Edited by Anna Kachkova
USAID to conduct another Pakistan shale study
The US will help Pakistan study its shale oil and gas reserves further, officials have told the Pakistani Express Tribune newspaper. The US Agency for International Development (USAID) will conduct and fund the study.
This is not the first time that the US has pioneered studies overseas, given that the country is the leader in shale development and US companies are interested in investing overseas – at least when the economics are favourable. The US Energy Information Administration (EIA) has studied shale reserves globally.
The initial study in Pakistan was also conducted by USAID, but it did not cover all of the country, including some parts of Balochistan, Sindh and Khyber-Pakhtunkhwa, reported the Express Tribune. It is unclear why these regions were not covered.
The initial USAID assessment indicated that Pakistan had deposits of 2.3 trillion barrels of shale oil and 10.159 quadrillion cubic feet (287.7 trillion cubic metres) of shale gas. Risked technically recoverable resources were estimated to be 14 billion barrels of shale oil and 95 trillion cubic feet (2.7 tcm) of shale gas.
The EIA’s numbers are different, with the agency first finding in 2011 that Pakistan had 206 tcf (5.8 tcm) of shale gas in the Lower Indus Basin alone, of which 51 tcf (1.4 tcm) were recoverable. In 2013, EIA increased the estimate to 586 tcf (16.6 tcm), of which 105 tcf (3.0 tcm) were technically recoverable.
If the initial USAID figures are confirmed or even increased, Pakistan could overtake Mexico, which is currently thought to have the world’s eighth largest shale oil and condensate reserves at 13 billion barrels. But it is not clear if the methodology used to assess these reserves is comparable.
Once the USAID’s new study has been completed, and the cost of the drilling assessed, the Pakistani government will create a policy framework for developing the resource, reported the Express Tribune, which is affiliated to the New York Times.