Fugro has successfully provided remote positioning services onboard a floating production storage and offloading (FPSO) vessel for Bluewater during a scheduled subsea inspection, repair and maintenance campaign in the North Sea.
A recent week-long operation included accurate remote configuration of the positioning systems onboard the FPSO, the assisting anchor handling vessel and the dive support vessel, with no Fugro survey crew offshore. This is the first fully remote FPSO heading control operation in the North Sea, enabling significant operational cost savings and de-risking through a reduction of offshore personnel.
Fugro managed the remote operation from its centre in Aberdeen via a robust low bandwidth connection, enabling command and control of the integrated survey system onboard the vessel and communication with the FPSO marine crew. Bluewater was also able to monitor operations in real time from shore via a web browser link.
Fugro has now provided over 100,000 remote service project hours for rig and FPSO positioning around the globe from its 7 key remote service centres, with 24/7 onshore supervision in Aberdeen, Bergen, Houston, Macaé, Perth and Singapore. Clients benefit from easy-to-install survey equipment and the flexibility of a scalable tiered service ranging from excursion monitoring to remote rig and FPSO positioning solutions.
Alastair McKie, Fugro’s Director for Positioning and Construction Support Europe, commented, “Fugro is pleased to have assisted Bluewater and the end operator with this key FPSO project and offer increased efficiencies via our remote service solutions. This critical positioning operation demonstrates the reliability and trusted performance of Fugro’s remote services and builds on the increasing demand we are seeing from energy operators and vessel owners to embrace remote operations and digital technology. The goal is not only to reduce total spend but also to optimise the number of personnel working offshore, simplify mobilisations and reduce health, safety and environmental exposure.”
Murray Burnett, Bluewater’s Subsea and Pipeline Superintendent commented “Fugro is offering a highly accurate positioning system that does not require someone in the field and is remotely accessed from onshore via a virtual private network (VPN). This offers considerable financial savings and we were impressed with how smoothly the operation ran.”
First cementless completion using Welltec Annular Isolation
Welltec has announced the first deployment of a truly cementless completion in the Republic of Congo during the second quarter of 2019. Building on the experience gained through the continuous deployment of the Welltec Annular Barrier (WAB) in the Moho North Albian field which was awarded the first quarter of 2017, Total E&P Congo has pushed the boundaries of metal expandable annular sealing technology even further by deploying the world’s first cementless completion using the Welltec Annular Isolation (WAI) in open hole.
The WAI uses multiple metal expandable packers to provide long length open hole zonal isolation to replace the functions of traditional cement, leading to significant gains in efficiency in the overall well construction process. It significantly reduces the free annulus space between the liner/casing and the open hole which can be beneficial in highly layered reservoirs of varying permeability where selective production, stimulation or water shut off is required. In addition to the efficiency gains, the simplified well completions operations enabled by the WAI eliminated multiple operational risks associated with the cementing process in depleted and over-pressured reservoirs.
“Total E&P Congo have utilized innovative technologies and methods to continually improve the drilling curve on the Moho North Albian field development project” Ronan Bouget, drilling and completions manager of Total E&P Congo, said. “We were early adopters of Welltec’s WAB technology which has assisted in ensuring zonal isolation and annular sealing (liner to formation) during the development of our major oil project in the Republic of Congo. The WAI was deployed as part of the global efficiency drive to reduce drilling expenditure whilst maintaining the beneficial productivity index in this highly heterogenous carbonate field. Our Albian Asset team led by Manfred Bledou and the completion department led by Guillaume Viger worked with Welltec to develop the technology. The simplicity of the WAI enabled us to successfully deploy the technology the first time without operational issues. We delivered a step change improvement in our well construction record and plan to deploy the WAI in subsequent wells - especially those identified as high-risk.”
“The WAI technology will without doubt transform how future wells are constructed in the industry” Gbenga Onadeko, senior vice president, Welltec Africa, said. “We are proud of this collaboration with Total E&P Congo to demonstrate our ability to deploy game-changing innovation that can simplify, eliminate risks and enhance operational efficiency. This world-first deployment of the WAI technology is very important as we progress our mission - to develop and deliver ground-breaking solutions which enable our client to optimize the management and development of their assets.”
Aker BP selected Optime Subsea as a provider of well access system and -services on the Norwegian Continental Shelf (NCS).
Optime Subsea’s system, Subsea Controls and Intervention Light System (SCILS), have now successfully completed a two well Plug & Abandonment campaign on the Jette field, saving rig time, personnel and equipment.
Aker BP is continously improving operations and lowering costs. After signing the new semi-submersible drilling rig Deepsea Nordkapp, a large, stable rig built specifically for the Norwegian climate, Aker BP announced the long term lease of Optime’s new subsea hydraulic pump Intervention Workover & Controls (IWOC) system.
Traditionally the IWOC systems typically have consisted of large 20 foot topside containers with equilly large umbilical and reels, carrying all hydraulics and electrical power. These systems may have a total weight of up to 50T.
Optime Subsea’s SCILS moves the hydraulic control from topside to subsea, resulting in no need for topside container and a dramatic reduction in size of the umbilical and reel. The SCILS have a total weight of 3 – 7T, depending on the reservoar size and configuration.
To illustrate how the SCILS differs from traditional IWOC systems and operations, Aker BP chose to demobilize the SCILS after its two well P&A campaign on the Jette field on the Nowegian Continental Shelf in the North Sea. In preparation for its new completions work on the Skogul field, Aker BP will perform the complete interface testing towards the Xmas Tree at Optime Subsea’s workshop in Notodden, Norway. This simplifies interface challenges which normally would be discovered on rig and thereby further saving the Norwegian based operator rig cost and time. This can only be carried out because of the small sized SCILS. It mobilizes or demobilizes in a day, compared to traditional systems requiring 5-7 days each.
“Aker BP continues to search for value creation by exploring new and innovative ways to optimize its assets and operations. We decided using Optime Subsea’s SCILS because it ties well into our strategy of continuous improvement and simplification of our well access operations. Using new technology always brings some risk associated with it, but the integrated planning resulted in a successful execution” says Mads Rodsjo, VP D&W Functional Excellence in Aker BP.
“We are very proud of how well the operations and one team relationship with Aker BP developed. We have a few more technology developments up our sleeve, but for the most part, our controls and intervention systems are modular and field proven and truly cuting edge in the industry. We look forward to grow the global supply of SCILS and similar systems” says Jan-Fredrik Carlsen, CEO of Optime Subsea.
Africa is taking the lead in the next phase of global LNG mega-projects. 2019 will shatter previous records for the industry.
Rystad Energy forecasts that LNG greenfield investment in 2019 will reach nearly $103 billion, the biggest investment year for the burgeoning industry to date.
Mozambique’s Area 1 and Area 4 projects, the latter of which is expected to secure a final investment decision (FID) from operator ExxonMobil by the end of the year, are making Africa the dominant LNG investment destination this year, with nearly one-third of total greenfield investment.
“Last week’s final investment decision by Anadarko for its Area 1 LNG project marks the beginning of a new phase for not only Mozambique and the African continent, but for the industry as a whole,” says Pranav Joshi, analyst on Rystad Energy’s Upstream team.
The greenfield capex for the Area 1 project is estimated at $15.6 billion, putting the project in the same league as the major LNG developments in the US, Russia and Australia. If ExxonMobil’s Area 4 does indeed reach FID this year, that will represent another $14.7 billion in greenfield expenditure in Africa, bringing the yearly total to 28% of the global tally for approved investments in newly sanctioned LNG projects.
“Area 1 is the largest LNG project that has been sanctioned in Africa to date and will also kick start the wave of sanctioning activity of other bigger LNG projects this year,” Joshi added.
Al Dhafra Petroleum has announced it has begun producing crude oil from Abu Dhabi’s Haliba field and discovered potential resources in three new fields in its concession area.
Al Dhafra Petroleum, a joint venture between the Abu Dhabi National Oil Company (ADNOC), the Korea National Oil Company (KNOC) and GS Energy, and one of ADNOC’s youngest operating companies, announced it has begun producing crude oil from Abu Dhabi’s Haliba field and discovered potential resources in three new fields in its concession area. The success of Haliba reinforces the UAE’s and South Korea’s strategic bilateral relations and reflects the importance ADNOC places on its long-term partnership with South Korea’s energy sector.
Haliba field, located along the southeast border of Abu Dhabi emirate, is a building block of ADNOC’s oil production capacity growth to 4 million barrels per day by the end of 2020. ADNOC said the initial production from the field would progressively increase to 40,000 bpd by the end of 2019 as Al Dhafra Petroleum further unlocks the substantial potential of the field.
Al Dhafra Petroleum embarked on an extensive appraisal program in Haliba field that enabled it to discover 1.1 billion barrels of original oil in place (OOIP), a significant increase from the 180 million initially estimated. At the same time, it discovered potential resources in three new fields – Al Humrah, Bu Tasah, and Bu Nikhelah – following intensive exploration programs.
This is the first time Al Dhafra Petroleum is producing crude since it was established in 2014 and, to commemorate the milestone, a special ceremony was held at ADNOC Headquarters, where His Excellency Dr Sultan Ahmed Al Jaber, UAE Minister of State and ADNOC Group CEO, hosted a government delegation from South Korea led by His Excellency Ilpyo Hong, Chairman of the Trade, Industry, Energy, SMEs, and Start-Ups Committee of the National Assembly of South Korea; and included His Excellency Youngjoon Joo, South Korea’s Deputy Minister of Trade, Industry and Energy; Suyeong Yang, President and CEO of KNOC; Yongsoo Huh, President and CEO of GS Energy; members of South Korea’s National Assembly; and government officials from South Korea.
“The start of production from Haliba field highlights the important role of energy cooperation in strengthening the close and deep-rooted strategic relationship between the UAE and South Korea,” Dr Al Jaber said. “ADNOC has a successful history of partnership with South Korea’s energy sector, and we continue to place great importance on this strategic partnership as we accelerate delivery of our 2030 smart growth strategy.
“First oil from Haliba demonstrates our ambition to unlock and maximize value from all of Abu Dhabi’s oil and gas resources to create long-term and sustainable returns for the UAE and our partners as we respond to the world’s growing demand for energy. ADNOC is committed to delivering a more profitable upstream business and expanding our oil production capacity, and the production from Haliba field is an integral part of achieving our targets.”
Al Dhafra Petroleum plans to accelerate oil production from these fields by utilizing modularized production units that provide swift and innovative production capability and will transport the oil for processing using trucks. This efficient approach can unlock immediate value by reducing the oil’s ‘discovery-to-market’ cycle to less than two years, increasing profitability and shareholder value.
“Given the utmost importance of securing a stable oil supply source to Korea, successful first oil production in Haliba field is a very meaningful event,” Ilpyo Hong said. “The announcement will strengthen the South Korea-UAE strategic bilateral relationship as the two countries’ mutual interests expand over the long term.”
ADNOC said Haliba field will serve as the main production hub in Al Dhafra Petroleum’s concession area and enable it to unlock value from other nearby prospects. Al Dhafra Petroleum continues to explore an additional 70 prospects in its concession area.
Al Dhafra Petroleum utilizes smart oilfield innovation at Haliba field to reduce operating costs while maximizing value from the development of other nearby marginal fields. Operational data is integrated into a centralized system that allows for remote monitoring of the site and provides unmanned facilities capability.
To optimize ADNOC’s infrastructure, the crude oil produced from the Haliba field is transported to ADNOC Onshore’s Asab Central Degassing Station for processing. After processing, the stabilized crude is then transported via ADNOC Onshore’s existing main oil lines to the marine export terminals for export.
Al Dhafra Petroleum – 60 percent owned by ADNOC and 40 percent by KNOC and GSE Energy, which is represented by the Korean Abu Dhabi Oil Consortium (KADOC) – is focused on exploring and developing its concession areas to assess the commercial value of several promising fields through an agile operating model.
ABB and Norwegian fast-growing oil and gas producer OKEA have signed a Memorandum of Understanding (MoU) agreement to support OKEA achieve substantial productivity gains using agile and dynamic business models.
The MoU reflects future potential for OKEA to leverage ABB’s global digital leadership and industry experience in sustaining lean and optimized operations for the future – with responsive new business models to maximize operational excellence, reduce time-to-value and support cost-effective field developments at a time of high technological change in offshore operations.
“We are pleased to express our joint efforts with ABB to further develop our collaboration through this MoU, which constitutes a framework for defining a strategic partnership related to digitalization initiatives,” said Dag Eggan, senior vice president of business performance, OKEA, said. “ABB is, and will continue to be, a key partner for OKEA in realizing our ambition to operate Draugen until 2040.”
The MoU will support OKEA in their strategy to maintain an efficient organization and scale production by leveraging ABB’s expertise in autonomous operations, digital solutions and advanced services.
“With deep-domain expertise and more than 50 years’ experience supporting oil and gas operators worldwide, we are confident ABB will create tremendous value for OKEA with this strategic collaboration,” said Tor-Ove Lussand, Local Business Manager, Norway, Energy Industries, ABB.
“ABB Ability™ – our unified digital offering extending from device to edge to cloud – combined with innovative business models, will enable a direct link between the technology and services we deliver, and the value created for OKEA.”
Libra Consortium has announced the final investment decision to contract the Mero-2 floating production, storage and offloading (FPSO) vessel to be deployed at the Mero field offshore Santos Basin in Brazil.
The FPSO will have a capacity to process up to 180,000 barrels of oil per day. The consortium plans four new production systems to be deployed in the Mero field. Mero-2 is the second, with first oil expected in 2022.
“Shell is the largest foreign producer in Brazil, which has become a heartland for us. Mero-2 is the latest in a series of FPSOs that will come online,” said Andy Brown, Upstream Director, Royal Dutch Shell. “From production to development, appraisal and exploration, we have a full funnel of long-life, resilient growth opportunities in the country, which is home to some of the best deep-water basins in the world.”
As one of Shell’s Core Upstream themes, Deep Water is set to generate robust cash flow for decades to come. Shell’s global deep-water business has a strong funnel of development and exploration opportunities in Brazil, the US, Mexico, Nigeria, Malaysia, Mauritania, and the Western Black Sea. Production worldwide is on track to reach more than 900,000 boe/d by 2020 from already discovered, established reservoirs.
Total has started up production at the La Mède biorefinery in southeastern France, with the first batches of biofuel coming off the line.
It is the final step in converting a former oil refinery into a new energies complex. Launched in 2015, the project represents a capital expenditure of €275 million.
The La Mède complex now encompasses: a biorefinery with a capacity of 500,000 tonnes of biofuel per year; an eight-megawatt solar farm that can supply 13,000 people; a unit to produce 50,000 cubic meters per year of AdBlue, an additive that reduces nitrogen oxide emissions from trucks; a logistics and storage hub with a capacity of 1.3 million cubic meters per year; and a training center offering real facilities and able to host 2,500 learners a year. Together, these new activities have maintained 250 direct jobs at La Mède.
As part of the site transformation, 65 per cent of the orders to remodel the complex were awarded to local businesses, representing 800 jobs and €140 million in revenue. Total also invested €5 million in the economic development of the Fos-Etang de Berre region, notably by supporting initiatives to create jobs, attract industrial projects and support contractors. That’s five times as much as a typical revitalization agreement.
The biorefinery can produce 500,000 tonnes of hydrotreated vegetable oil (HVO), a premium biofuel. La Mède will produce both biodiesel and biojet fuel for the aviation industry. It was specifically designed to process all types of oil. To promote a circular economy its biofuels will be made 60 to 70 per cent from sustainable vegetable oils such as rapeseed, palm and sunflower and 30 to 40 per cent from treated waste such as animal fats, cooking oil and residues.
As part of an agreement with the Government in May 2018, Total has pledged to process no more than 300,000 tonnes of palm oil per year — less than 50 per cent of the total volume of raw materials needed — and at least 50,000 tonnes of French-grown rapeseed, creating another market for domestic agriculture.
All the oils processed will be certified sustainable to European Union standards. In addition, as part of its palm oil procurement process, Total is taking an extra step by introducing strengthened control of sustainability and respect for Human Rights.
“I’d like to thank the teams for all their hard work these last four years to convert our La Mède refinery,” Bernard Pinatel, president, refining and chemicals, said. “Biofuels are fully renewable and an immediately available solution to cut carbon emissions from ground and air transportation. When produced from sustainable raw materials, as at La Mède, they emit over 50% less carbon than fossil fuels. Our biorefinery will allow us to make biofuels in France that were previously imported.”
Reliance Industries Limited (RIL) and BP have announced the sanction of the MJ project (also known as D55) in Block KG D6, offshore the east coast of India.
MJ is the third of three new projects in the Block KG D6 integrated development plan and its approval follows sanctions for the development of 'R-Series' deepwater gas field in June 2017 and for the Satellites cluster in April 2018.
Together the three projects are expected to develop a total of about 3 trillion cubic feet (tcf) of discovered gas resources with a total investment of circa INR 35,000 crore (US$5 billion). These projects together, when fully developed, will bring about 1 billion cubic feet a day of new domestic gas onstream, phased over 2020-2022.
Mukesh Ambani, Chairman and Managing Director of RIL, said: "Bringing these three discoveries to production, as promised in 2017, by leveraging the existing infrastructure has been the primary objective of the Reliance - BP Joint Venture. The gas will satiate the increasing demand for clean fuel in the country, save foreign exchange and reduce dependency on imported gas. We are excited about bringing this gas onshore from our third project on the East Coast of India to power the Indian economy with an environment-friendly fuel and help strengthen energy security while moving towards meeting India's Climate Change Goal.
Bob Dudley, BP Group Chief Executive, welcomed the investment decision: "We are building an important upstream business in India, helping to supply the country's growing gas market. Working closely with Reliance, we are efficiently developing discovered resources, with focused exploration to give options for the future. This latest investment is a further demonstration of BP's commitment to India and helps support India in addressing the dual challenge and moving to a low carbon future."
MJ is a gas condensate field and is the third field under development as part of the KG D6 integrated development campaign. The project is in 700-1100 metres water depth, with a well depth of 4200 metres below mean sea-level in a high-temperature and pressure environment. It comprises of wells connected to a subsea production, with tie-back to a Floating Production Storage and Offloading (FPSO) vessel to process and separate liquids, and gas which will be exported to the onshore terminal through one of the existing 24-inch trunk pipelines. The project is expected to begin production in mid-2022.
The first of the three KG D6 projects under development, the R-Series project, is in execution phase. All six wells have been drilled. With this, the first installation campaign; in which a 54-line km, 18"/4" piggyback flow line was installed in 1920m water depth – setting a new world record for deep-water pipelay installation, has been successfully completed. First gas from this project is on-schedule and expected by mid-2020. The second project, the development of the Satellites cluster, is on track with all major contracts awarded to deliver first gas by mid-2021. The MJ project will draw on execution synergies with the R-Series and Satellite projects being developed, concurrently.
India today consumes over 5 billion cubic feet a day of natural gas and aspires to double gas consumption by 2022. Gas production from KG D6 integrated development is expected to help reduce India's import dependence and amount to over 10% of the country's projected gas demand in 2022; benefiting India and domestic consumers at large.
ExxonMobil and SABIC have announced the decision to proceed with the construction of a chemical facility and a 1.8 million metric ton ethane steam cracker in San Patricio County, Texas, leading to thousands of high-paying jobs and billions in economic output.
“Building the world’s largest steam cracker, with state-of-the-art technology, on the doorstep of rapidly growing Permian production gives this project significant scale and feedstock advantages,” said Darren W. Woods, chairman and chief executive officer of ExxonMobil. “It is one of several key projects that provide the foundation for significantly increasing the company’s earnings potential.”
The joint-venture between ExxonMobil and SABIC, called Gulf Coast Growth Ventures, received final environmental regulatory approval in June 2019 to build an ethane steam cracker, two polyethylene units and a monoethylene glycol unit. Construction will begin in the third quarter of 2019 and startup is anticipated by 2022.
“SABIC is very pleased to move forward on this third joint venture with ExxonMobil – the first to be operated outside of Saudi Arabia,” said SABIC Vice Chairman and CEO Yousef Al-Benyan. “This project will not only increase global diversification for our company, but will also continue to create value within our new home of San Patricio County through creating jobs and supporting economic growth. With this project, we look forward to further building our business presence in the U.S. and serving the communities and customers in the North and South American markets even more effectively.”
The project is expected to create more than 600 permanent jobs with average annual salaries of $90,000 per year. An additional 6,000 high-paying jobs will be created during construction. A preliminary independent study, conducted by Impact DataSource, estimates the project will generate more than $22 billion in economic output during construction and $50 billion in economic benefits during the first six years of operation.
The facility will produce materials used in the manufacturing of various consumer products including automotive coolants, packaging, agricultural film and building, construction materials and clothing.
Project construction will be led by four primary engineering, procurement and construction companies: The Wood Group, McDermott & Turner Industries Group, Chiyoda & Kiewit and Mitsubishi Heavy Industries & Zachry Group.
Gulf Coast Growth Ventures is a unique opportunity created by the abundance of low cost U.S. natural gas, and is part of ExxonMobil’s Growing the Gulf initiative initiative, which outlined plans to build and expand manufacturing facilities along the U.S. Gulf Coast, creating more than 45,000 high-paying jobs across the region.
The project is part of SABIC’s growth strategy to build new petrochemical facilities in key markets, including the Americas, to address industry demand and achieve the company’s 2025 strategy.
Ownership interests in the Gulf Coast Growth Ventures project is 50 percent ExxonMobil and 50 percent SABIC, with ExxonMobil as site operator. ExxonMobil and SABIC bring unmatched expertise to this project, having worked together in petrochemical ventures for more than 35 years. The Gulf Coast Growth Ventures project expands that successful international relationship.