Trelleborg’s engineered products operation has successfully completed its supply of floatover equipment for the PETRONAS NC3 gas field, located in Block SK316, 200 kilometers North of Bintulu, Sarawak in Malaysia.
Trelleborg provided PAPE Engineering, an engineering company responsible for the transportation and installation of the platform jacket and topside, with four Leg Mating Units (LMUs), as well as four sway fenders, four loadout pads and four deck support units (DSU).
Mr. Olivier Beauclair, Director for Platform Transportation and Installation at PAPE, commented: Having worked closely with Trelleborg to great success on previous projects, we know that they're able to supply proven quality solutions with considerable ease of use and offer quick turnaround times - both imperative for a high stakes project like PETRONAS NC3. This meant that we had no hesitation it was entirely suited for the project.
In addition, Trelleborg site service engineers were able to provide supervised on-site support, ensuring a seamless LMU installation within the topside of the Central Processing Platform.
Performed at the fabrication yard prior to the floatover process, the LMU installation provided PAPE with assured and risk-free performance before the floatover operation commenced.
Vincent Tan, Sales and Marketing Manager at Trelleborg’s engineered products operation, commented: At Trelleborg, we aim to support every aspect of customer projects with a fast response and high quality solutions, whilst making sure we meet all delivery schedules and site requirements.
With a global reach and local support, we’re able to provide exactly that. Our manufacturing facility in Singapore ensured that PAPE had the local feet on the ground support, whenever it was needed.
For more information about Trelleborg’s engineered products operation, or any of its products and solutions, please visit the Trelleborg Engineered Products website.
This spring and summer saw buzzing activity at water depth of 1300 meters on the Aasta Hansteen field. Four vessels have carried out successful field operations for nearly 200 days.
The waters on the Aasta Hansteen field are deep, very deep, as much as 1300 meters to be precise, but for the deep-sea fish there was much to watch on the field this year.
Pipelines, risers and spoolers have been installed and hooked up to subsea templates and umbilicals that were installed last year.
The pipelines have been pressure-tested and prepared for production, and mooring lines have been carefully installed on the seabed – everything has to be ready before the platform arrives in 2018.
The Aasta Hansteen field is located in one of the harshest environments along the Norwegian coast, even if the weather is better in the summertime in this area too.
Illustration: The Aasta Hansteen platform will be the largest SPAR platform in the world. (Illustration: GeoGraphic / Statoil)
The installation season is shorter compared to other places along the coast, and the weather windows are shorter and more unpredictable. In addition, the field lies farther from shore.
"It is definitely more complicated to plan subsea, umbilical, riser & flowlines (SURF) operations here than in the North Sea,” says Helge Hagen, project manager for the Aasta Hansteen SURF project.
It is also far down to the seabed, and the vessels have to carry heavy loads of pipelines and umbilicals designed for ocean depths of 1300 meters.
“We fully depend on good suppliers and Subsea 7 has done a great job in this year’s campaign,” says Per Rusås, project director for Aasta Hansteen.
He praises the SURF team for properly planning and completing this year’s marine season and avoiding any serious incidents.
“It takes knowledge, experience and hard work to reduce risk in operations like these. The result is a perfect illustration of how to conduct an offshore installation campaign, and demonstrates Statoil’s ability to carry out complex deep-water operations,” says Rusås.
This year’s campaign started at full speed on 27 April, when the Seven Oceans vessel mobilized at Subsea 7’s base at the island of Vigra in West Norway by spooling pipelines and risers on board the vessel. They were installed on the field during a couple of months.
“Seven Oceans had a demanding scope, yet we managed to halve the time spent on waiting on weather from an estimated 20 days to 10 days,” says Kjersti Kværnæs, pipeline and marine manager. That was not only due to good weather luck!
“We split the most weather-sensitive operations into sub-operations and consequently we did not have to wait for long weather windows to carry out the operations,” she explains.
This is the first time Statoil uses BuBi pipes, which consist of liner pipes and steel catenary risers for corrosion protection.
At such depths it is namely possible to use rigid risers, which also cost less than flexible risers.
During two weeks in June the spoolers were also installed. Normand Oceanic did the job perfectly and ahead of schedule.
“During this operation we did not have to wait on weather at all, and in mid-July the job was done,” says Kværnæs.
The spools were manufactured locally by Aker Sandnessjøen, who also manufactured the subsea templates.
Last year the subsea templates and umbilicals were installed on the seabed. After the pipelines, spoolers and risers had been placed on the seabed, it was Seven Viking’s turn.
This vessel carried out all the hook-up jobs before flushing and pressure-testing all pipes.
Finally, the vessel filled the pipes with nitrogen to make them ready for production when the platform arrives.
The vessel also connected Polarled, the 482-kilometre-long pipeline from the Aasta Hansteen field to Nyhamna, to the riser that will send processed gas from Aasta Hansteen, marking the first physical contact between the two mega-projects.
“When the platform arrives the risers that are currently in wet storage on the seabed will be pulled up by the vessel and connected to the platform,” explains Hagen.
Safely stored on the seabed are also the mooring lines that will keep the huge platform in place. A total of 17 mooring lines, each measuring 2500 meters, will be installed in a circle around the platform. On the seabed they are connected to the suction anchors from Momek that were installed last year. The fiber ropes have been installed by Skandi Skansen.
The Normand Oceanic, Seven Viking and Skandi Skansen have all been in shuttle traffic between the Asta Hansteen field and Sandnessjøen this summer, totaling 17 port of calls.
When large construction vessels like this arrive, they lead to buzzing activity, on the base, at Aker’s premises and in the local community in general – involving a range of services from food supply to transportation.
“The Aasta Hansteen SURF project has led to major spin-offs in North Norway, for example manufacturing of subsea templates, spooles and suction anchors as well as coating of pipes for the Polarled pipeline and also base services. Drilling on the field will start at the turn of the year 2017/2018, involving helicopter traffic from Brønnøysund and base services in Sandnessjøen. In the operations phase Aasta Hansteen will be even more visible in the north,” says Torolf Christensen, project director for Aasta Hansteen.
The field operations this summer have involved close to 200 vessel days. The result can only be seen by the deep-sea fish.
Watch video here
Trelleborg’s engineered products operation has supplied a selection of bearing solutions for the world's first floating liquefied natural gas (FLNG) project, Shell’s Prelude FLNG.
Trelleborg has manufactured and delivered 52 vertical elastomeric bearings and 156 horizontal bearings for use on the 13 modules onboard the facility, as well as 40 turret bogey bearings to enable natural movements of the turret.
Shell’s Prelude FLNG
Responsible for procuring bearings for the topside modules, Byoung-Gark Park, Topside Structural Engineer for Samsung Heavy Industries, said: Many of Prelude’s topside modules weigh as much as a single typical offshore platform. In fact, along with its contents, Prelude is expected to weigh a total of 600,000 tons. So, optimum quality and performance of the bearings used to secure each module is vital. We have worked closely with Trelleborg previously and are very confident in their ability to manufacture first class bearings. We were keen to involve their expertise on this prestigious project too.
Trelleborg’s elastomeric bearings are steel plate laminated and installed between the hull of the facility and its modules. They accommodate axial, shear and rotational movement to keep the modules safe from impact, damage and deformation. Similarly, they prevent the concentration of excessive strains and stresses around the mounting points of the modules and the hull caused by adverse sea and weather conditions.
JP Chia, Engineering Manager for Trelleborg’s engineered products operation, says: We design and manufacture all of our elastomeric bearings specifically for their application, to ensure that they always perform exactly as required. This approach was especially important for the Prelude topside, to guarantee that the record-breaking weight could easily be supported over its life. We are very proud to have been selected to supply such a landmark project.
All of Trelleborg’s bearings are tested by its engineering team. They check the design for specified loads and deformations and the fatigue performance by means of crack growth analysis calculations.
Additionally, they examine wave action and the resulting multi-directional loads between a facility’s hull and topside modules. After production they are a 100% individually tested according a specified test procedure.
For more information about Trelleborg’s engineered products operation, or any of its products and solutions, please visit the Trelleborg Engineered Products website.
Following the accident involving COSLInnovator on 30 December 2015, some 100 semi-submersible rigs approved by DNV GL will be reviewed. Preliminary assessments indicate that a limited number of rigs will be subjected to modifications or operational limitations.
The semi-submersible rig COSLInnovator was drilling for Statoil in the Troll field when it was hit by a large, steep wave. Several windows on the rig's two lower decks were shattered. One person was killed. “Since the incident, we have made great efforts to identify what happened, understand how this could happen and, most importantly, implement actions to prevent similar incidents from occurring again,” says Ernst Meyer, DNV GL Director for Offshore Classification. “We have been working with rig owners, designers, operators and authorities towards a common goal; to ensure the safety of all those working on board the rigs.
COSLInnovator
The incident investigation report presented by the Norwegian Petroleum Safety Authority in April 2016 concluded that the incident involving COSLInnovator has provided new knowledge that must be utilized in order to prevent similar incidents in the future. DNV GL therefore published a new technical guideline (OTG-13 – Prediction of air gap for column-stabilized units) as early as in June 2016. This gives a consistent and updated approach for calculating the air gap - the clearance between the highest wave crest and the bottom of the deck box in all relevant sea conditions.
Last week, DNV GL asked all owners of DNV GL-classed semi-submersible rigs to provide updated documentation of each rig's air gap.
Rigs that, based on the new technical guideline (OTG-13), can confirm a positive air gap, will be able to operate as before without reinforcement or operational limitations. This is expected to apply to most of the semi-submersible rigs operating on the Norwegian shelf.
“I can't indicate how many rigs have negative or positive air gaps before each rig's calculations have been performed,” says Ernst Meyer.
“A limited number of rigs may not have a positive air gap, but most of these will be able to avoid changes. The prerequisite is that they are able to document a positive air gap for a specific location, or that they simply do not have windows that may be exposed to waves.”
He elaborates on the consequences for the other rigs – those that are unable to prove a positive air gap in all sea conditions – including the hundred-year wave:
“Initially (for the next winter), these rigs will be required to remove windows in exposed zones. If the strength calculations show that further structural modifications are necessary, such modifications will be required as part of the permanent solution.
“The most important thing is that the windows are removed before the coming winter. This action eliminates the largest risk elements if a similar incident occurs,” Meyer explains. He emphasizes once again that operational limitations and limitations with regard to areas of operation may solve the air gap issue in the short term.
Rigs that are certified for worldwide operation must be documented according to North Atlantic wave data. Most rigs operate in milder areas, such as the North Sea, and can postpone modifications that may be necessary in the Norwegian Sea or Barents Sea.
DNV GL is the classification body that certifies the largest number of semi-submersible rigs, and these rigs operate under the most extreme weather conditions globally. The company works continuously to improve the class regulations used in certification work through future-oriented research and the thorough examination of and learning from incidents and accidents.
“The work behind the new guideline includes the use of updated statistical weather data and knowledge acquired from several independent model tests conducted in light of the COSLInnovator incident. We have also learned from previously conducted model tests and from operational experience after 40 years classing hundreds of similar rig types,” Ernst Meyer concludes.
Paris, France – October 13, 2016
CGG announced that it has been awarded an extensive multi-client program by the Instituto Nacional de Petroleo (INP) to acquire seismic data offshore Mozambique. The multi-survey program is designed to improve industry insight into the region’s geology and provide oil and gas companies with a greater level of understanding of the country’s prospectivity.
The program includes a 2D survey of over 6,550 km in the offshore Rovuma basin, including blocks R5-A, R5-B and R5-C, and a large 3D survey over the Beira High in the Zambezi Delta. The 3D survey is expected to be up to 40,000 km², subject to pre-commitment. It will cover blocks Z5-C and Z5-D and surrounding open acreage in this deltaic area which is believed to be prospective. CGG has also been awarded an onshore airborne gravity and magnetic survey in the Southern Mozambique Basin.
Location map of the CGG multi-client surveys in Mozambique.
The proposed multi-client seismic program in the Mozambique Zambezi region will form part of a comprehensive, fully integrated geoscience package that will give participating companies a better overall understanding of the region. Marine gravity and magnetic data will be acquired simultaneously with the seismic to aid regional interpretation. The interpretive phase of the program will benefit from the full range of geoscience expertise from CGG’s Geology, Geophysics & Reservoir businesses. This will include geological and remote sensing expertise from Robertson and NPA Satellite Mapping.
Jean-Georges Malcor, CEO, CGG, said: “CGG has a long track record of delivering successful multi-client programs in the Sub-Saharan Africa region and this award underlines the extent to which our reputation for high-quality services and delivering value to our clients is recognized not just by oil and gas companies but also by national governments. As our first multi-client projects in Mozambique, these awards fit well with CGG’s long-term multi-client strategy to provide our clients with the most advanced understanding of the subsurface across the world’s key basins. The 5th License Round award process undertaken by the INP in 2015 saw a high level of interest in the Zambezi region and we believe our multi-client projects will highlight the exploration upside potential.”
Cybercrimes cost energy and utilities companies an average of USD 12.8 million each year in lost business and damaged equipment1. Platform operators need confidence that countermeasures can deal with bigger and more sophisticated cyber-attacks. DNV GL is now collaborating with Shell, Statoil, Lundin, Siemens, Honeywell, ABB, Emerson and Kongsberg Maritime to develop best practice in addressing this threat. Other companies are still welcome to join.
Cyber security is a growing issue in the oil and gas sector since critical network segments in production sites, which used to be kept isolated, are now connected to networks. The trend is towards remote operations, remote maintenance and tighter inter-operability with centralized process data and plant information. Old and outdated installations are at particular risk and require risk mitigation actions.
“We see that cyber-security incidents are increasing with attempted attacks on a daily basis. By collaborating with others in the industry, we can ensure that we end up with one globally applicable regulation that is suitable for the oil and gas sector,” says Rune Wærstad, Control & Automation Engineer, Shell.
To address these challenges, DNV GL has established a Joint Industry Project (JIP) together with Shell, Statoil, Lundin, Siemens, Honeywell, ABB, Emerson and Kongsberg Maritime. In addition, the Norwegian Petroleum Safety Authority will take part as an observer. The JIP will produce a guideline for protecting oil and gas installations against cyber-security threats. The IEC 62443 standard will be used, but will be tailored to the oil and gas industry. The standard defines what to do, while the guideline will describe how. The JIP will result in:
“Dealing with cyber-security challenges has become a key focus area for the oil and gas sector. Attacks are becoming increasingly costly and harder for companies to recover from. This JIP will lower the risk of cyber-security incidents and trim costs for operators, contractors and vendors by reducing the resources needed to define requirements and by driving a standardized approach,” says Pål Børre Kristoffersen, Principal Consultant, DNV GL – Oil & Gas.
The scope of the JIP is to produce cyber-security guidelines to simplify and clarify the use of IEC 62443 for the FEED, projects and operations. Good practice and reusable patterns are to be produced. The JIP will result in a Recommended Practice (RP) for Industrial Automation and Control Systems in 12 months' time.
DNV GL is currently assisting Total E&P Norge with cyber-security risk management for the Martin Linge field development and associated operations offshore Norway. DNV GL’s scope of work includes the day-to-day management and coordination of cyber security during the project phase and through preparations for operation, with a specific focus on integrated control and safety systems. The project also aims to raise awareness of cyber-security risks and to train personnel to take simple preventative measures.
See more about the JIP here.
Airborne Oil & Gas announces the start of a project to qualify Thermoplastic Composite Pipe (TCP) for a deepwater jumper spool application for French operator Total.
The non-corrosive and spoolable Thermoplastic Composite Pipe (TCP) is Airborne Oil & Gas’ answer to today’s industry call for cost effective spools, well jumper, flowline and riser solutions to deal with corrosive fluid conditions and deep water environments: TCP Flowlines, Jumpers and Risers are flexible, corrosion free, light weight and have high strength and thus enable a significant reduction in total installed cost. For the deepwater spool application, the TCP offers the possibility to save time and cost due to the inherent flexibility of the product. TCP allows installation without high-precision subsea metrology, as is the case for rigid steel spools.
The Airborne Oil & Gas’ TCP that will be qualified on this project targets deep water applications. Client Total foresees the first application by the company to be for water injection well jumpers: “The possibility with TCP to handle large deflections, the ability to cut-to-length and terminate the pipe at location and the subsequent installation with small vessels, make a compelling business case for TCP jumpers. We estimate we can achieve considerable cost savings by using TCP jumpers” says Frédéric Garnaud, R&D Deep Offshore Program Manager with Total.
Airborne Oil & Gas has been working with Total in the development of TCP since the start of the Cost Effective Riser Thermoplastic Composite Riser JIP in 2009. “The start of this project underpins our long-lasting relationship with Total. It demonstrates their trust in Airborne Oil & Gas’ ability to provide cost effective solutions that address the challenges of today’s SURF market” says Bart Steuten, Business Development Manager with Airborne Oil & Gas.
The project includes the manufacturing and qualification testing of full-scale (6 inch ID) prototypes and is planned to deliver qualification to DNVGL standard RP-F119 in Q1 2017.
The world’s first subsea gas compression system has now been in operation for one year on the Åsgard field. The system has been running like a Swiss clock with practically no stops or interruptions.
lllustration of Åsgard subsea gas compression. Image credit: Statoil
It was in September 2015 Statoil and its partners started up the world’s first subsea gas compression system on the Åsgard field in the Norwegian Sea.
“Quality in all sections of the project and also during operation has contributed to maintain a system regularity of close to 100% through its first year of operation,” says Halvor Engebretsen, vice president for Åsgard operations.
“Before start-up we carried out extensive testing, commissioning and verification of the technology, and thereby we could remove errors and weaknesses before the installation was placed on the seabed. We have already benefitted from this effort by stable and good operation,” he continues.
With this new and ground-breaking technology, the recovery from the Mikkel and Midgard reservoirs has been increased by as much as 306 million barrels of oil equivalent (boe), corresponding to a medium-sized field on the Norwegian continental shelf (NCS) and extending the fields’ life to 2032.
“During the first year of operation we have raised production by an excess of 16 million boe. Based on today’s prices the value added amounts to more than NOK 5 billion,” says Engebretsen. The recovery rate from the Midgard and Mikkel reservoirs on Åsgard has been raised from 67% to 87% and from 59% to 84% respectively.
“Åsgard subsea gas compression is one of Statoil’s most radical innovation projects. The technology represents a quantum leap that may contribute to considerable improvements in both recovery rate and lifetime for a number of gas fields.
The technology that has been in operation for a year was matured through many years by strong in-house expertise. In close collaboration with suppliers such as Aker Solutions, MAN and Technip, Statoil has qualified more than 40 new technologies.
“We have built test facilities at K-lab, storage and maintenance capacity at Vestbase, and we have access to ships that are capable of handling installation of large subsea modules. By reusing this technology, we have great opportunities for simplification and efficiency improvements, and for reducing carbon footprints of future gas compression systems,” explains Engebretsen.
The technology also represents a significant reduction in energy consumption and carbon emissions in a lifecycle perspective on Åsgard, compared to a compression platform. This technology represents a potential for further carbon reductions through use in future subsea solutions.
Åsgard Subsea Gas Compression video: Watch here
BP has taken the decision not to progress its exploration drilling program in the Great Australian Bight (GAB), offshore South Australia.
The decision follows the review and refresh of BP’s upstream strategy earlier this year, which included focusing exploration on opportunities likely to create value in the near to medium term, primarily building on BP’s significant existing upstream positions.
BP has determined that the GAB project will not be able to compete for capital investment with other upstream opportunities in its global portfolio in the foreseeable future.
“We have looked long and hard at our exploration plans for the Great Australian Bight but, in the current external environment, we will only pursue frontier exploration opportunities if they are competitive and aligned to our strategic goals. After extensive and careful consideration, this has proven not to be the case for our project to explore in the Bight,” said Claire Fitzpatrick, BP’s managing director for exploration and production, Australia.
“This decision isn’t a result of a change in our view of the prospectivity of the region, nor of the ongoing regulatory process run by the independent regulator NOPSEMA. It is an outcome of our strategy and the relative competitiveness of this project in our portfolio.”
Fitzpatrick said BP has informed federal and state governments of its decision.
“This decision has been incredibly difficult and we acknowledge it will be felt across the South Australia region. We have made significant progress with preparations for drilling in the Bight with the support of communities and federal, state and local governments. We acknowledge our commitments and obligations and our priority now is to work with government and community stakeholders to identify alternative ways of honoring these.”
BP has also consulted with its joint venture partner, Statoil, who fully understand BP’s change in strategic direction and accept BP’s decision.
“BP is a long-term, significant investor in Australia, most visibly through our retail network and refinery and also as partners in the North West Shelf and Browse ventures,” added Fitzpatrick. ”We expect to continue to consider further opportunities to invest and grow our business here.”
BP was awarded exploration licenses for four blocks in the Ceduna area of the GAB in January 2011. Seismic data was acquired in the area in late 2011-early 2012. Statoil acquired a 30% interest in the licenses in 2013, BP remained operator with 70% interest.
BP has a contract with Diamond Offshore Drilling for the provision of a new Moss CS60E design semisubmersible drilling rig, which Diamond commissioned Hyundai Heavy Industries to build and is specially designed for use in deep water and harsh marine environments. BP’s decision does not impact this rig contract.
Fugro is marking a 35-year history of providing an asset integrity program on one of the Ninian oil field platforms in the North Sea. Operator CNR International is working with Fugro to monitor the structural integrity of the Ninian Southern Platform (NSP) using a permanent online monitoring (OLM) system. Following completion of initial structural integrity measurements in 1979, Fugro installed the OLM system on the platform in 1985 and since then it has carried out multiple upgrades. The current system is contracted through to 2020.
Accelerometers positioned at various locations on the platform combine with a wave radar to help correlate structural motions with wave conditions. These sensors allow Fugro to monitor the sway and torsion natural frequencies of the platform in response to changing weather patterns – any significant change in these values could indicate a loss in stiffness and would require further investigation. The OLM system is interrogated daily by Fugro’s onshore team, who check key parameters and assess data trends. Communications with the offshore system are conducted via a link to CNRI’s offices in Aberdeen and then offshore via CNRI’s network.
The importance of online monitoring was highlighted during a moderate winter storm in 2006, when Fugro quickly detected and located a brace failure event on the east face of the platform; this structural failure was later confirmed by an inspection. The multiple redundancies in the structure meant that the platform remained in a safe and useable condition until summer 2007, when the necessary repairs were carried out. Fugro continued to monitor NSP closely throughout this important period.
Fugro Project Manager Waheed Siddiq, who leads the OLM activities on NSP, said, “It’s a privilege to provide our asset integrity solutions to the structural team at CNRI. After more than 35 years of monitoring NSP, our analysts know exactly how it behaves in all weathers; this intimate knowledge means we are able to identify any structural issues very quickly and accurately, and can alert CNRI immediately.”
Mark Wilson, Structural Technical Authority at CNRI said, “The support we get from Fugro is a vital part of our overall integrity management of this key asset. The information provided by the continuous monitoring of the structure helps us optimise our underwater inspection and provides an additional level of confidence in the condition of the platform.”
CNR International (CNRI) forms part of Canadian Natural Resources Limited, one of the largest independent crude oil and natural gas producers in the world. CNRI’s portfolio spans offshore interests in the UK sector of the North Sea and offshore Africa in Cote d’Ivoire, Gabon and South Africa.
The Dresser-Rand business, part of Siemens Power and Gas Division, recently delivered power generation equipment for a combined cycle power plant (CCPP) for the Shell Appomattox deep-water oil and gas floating production platform. The platform will be located 80 miles off the coast of Louisiana in the Gulf of Mexico and is slated to start production around the end of this decade. The ~150 megawatt (MW) CCPP will feature four 27 megawatt (MW) gas turbine-driven generator sets equipped with heat recovery systems and a 40 MW steam turbine generator.
Photo courtesy: Dresser-Rand
The gas turbine gen-sets are self-contained mini-modules complete with all electrical wiring, piping, tubing and controls. The gen-set, ancillary equipment and baseplate remain connected after unit testing, substantially reducing the time required to install, commission and start-up the packages.
With CCPPs, a gas turbine generator produces electricity while the waste heat from the gas turbine is used to make steam to generate additional electricity via a steam turbine. The CCPP for the Shell Appomattox platform will improve overall fuel efficiency, reduce emissions of greenhouse gases, and increase total power generation for the platform.
“This project demonstrates the Dresser-Rand business’ unique capabilities to deliver full solutions for both power generation and oil and gas applications. Combined cycle power plants built for offshore applications are rare and we’re pleased to leverage our comprehensive portfolio to produce a solution that meets all of Shell’s requirements,” said Jesus Pacheco, Executive VP New Equipment Worldwide, Dresser-Rand business. “Our team designed and manufactured a compact, lightweight solution that will operate reliably and safely under the harsh conditions inherent in offshore applications.”
The packages feature a compact design and reduced weight to accommodate the platform’s footprint constraints. The design allows for easy accessibility to the package components for maintenance and service, along with adequate workspace.
The steam turbine generator package was manufactured in Wellsville, NY and packaged in Olean, NY. An 18.5 MW load test was performed on the steam turbine generator set using the steam-producing capability at the Olean facility. The gas turbine generator packages were designed in Kongsberg, Norway.
The Industry Technology Facilitator (ITF), together with Energie Beheer Nederland (EBN) and Petroleum Development Oman (PDO), has launched a joint industry project (JIP) which will reduce time and costs for oil producers to determine whether gas fields are economically viable.
The PETGAS III (Petrophysics of Tight Gas Sandstones) project sees the continuation of the successful work being conducted by University of Leeds in examining the petrophysical properties of tight gas sandstones. A robust database of key petrophysical properties has been formed to make rapid estimates of the properties of unknown samples based on their microstructure. Its specialist software, PETMiner, has been developed to visualise this and other petrophysical properties data.
The database of the petrophysical properties of tight gas sandstones will be used to improve the interpretation of wire-line log data for the characterisation of tight reservoirs during exploration, appraisal and production.
ITF CEO, Dr Patrick O’Brien
The project partners, EBN and PDO, are contributing £321K in total and the project, now in its third phase, will run for a period of three years. The project remains open to late participants.
Professor Quentin Fisher of University of Leeds, the principal researcher of the project said: “When oil producers are developing low permeability objectives, the petrophysical properties largely determine whether gas fields are economically viable. Current methods used in the industry are both expensive and time consuming.
The PETGAS research, which is now in its third stage, has been transformative in creating a workflow, database and datamining software that allows operators to reduce the cost and time to estimate to petrophysical properties of tight gas sandstone prospects.”
ITF CEO, Dr Patrick O’Brien said: “At ITF, we are seeing new opportunities for technology developers as the pursuit to increase efficiency is forcing the oil and gas industry to look for new technologies and solutions. The launch of a new phase of the PETGAS project demonstrates the leading edge work of UK Universities, and how the joint industry project model enables operators to effectively leverage the information they share into an advanced software model to radically transform industry outcomes. The work of the PETGAS JIP could in time play a key role in unlocking the significant, yet untapped, potential of stranded gas resources in the Southern North Sea and beyond.”
The PETGAS consortium has been running for eight years and has received sponsorship from San Leon, BG, BP, EBN, Engie, Shell and Wintershall. Results of PETGAS I and PETGAS II have been used by industry to justify drilling new prospects and to improve understanding of the controls on gas and water production in existing fields, which has shaped appraisal and production strategies. The PETGAS III project will extend the database by a further 15 samples per sponsor and continue the extensive special-core-analysis (SCAL) test work on a further seven samples per sponsor.
ITF is driving oil and gas technology development and collaboration. With a membership of international oil and gas operator and service companies, the industry technology facilitator has launched over 200 innovative joint industry projects. ITF champions technology development and believes investment is crucial to solving the most pressing challenges the industry faces in securing reserves and maximising economic recovery.
The Plan for Development and Operation (PDO) for the Dvalin field (previously named Zidane) has been handed over to the Ministry of Petroleum and Energy in Norway by operator DEA. Dvalin will be the company’s first operated field development project in Norway.
The Dvalin license plans to produce a total volume of approximately 18.2 billion cubic meters of natural gas from two reservoirs. The development cost is estimated to 1.1 billion Euros (10 billion Norwegian Kroner), with planned production start in 2020. “It’s is a major step for DEA to hand-in the PDO and to transfer this project into the next phase,” says Thomas Rappuhn, CEO of DEA Deutsche Erdoel AG. “The Dvalin development will contribute significantly to DEA’s ambition to further grow our business in Norway,” Rappuhn adds.
Dvalin will be developed with a four wells subsea template, which is connected to the Heidrun platform. At Heidrun, the gas will be partly processed in a new module, before the gas is transported in a new export pipeline to Polarled, going to the Nyhamna onshore gas terminal. At Nyhamna, the gas will be processed and transported to the European market.
Image courtesy: DEA Group
“Dvalin is DEA’s first development as field operator in Norway, and we are looking forward to the upcoming tasks,” says Hans-Hermann Andreae, Managing Director of DEA Norge.
“Together with our partners, we have come up with a development solution with sustainable long term economics in an environment of low market prices”, Andreae underlines. Creative work in the project team and market developments in the supplier industry have made it possible for the partnership to make the project economical sound.
“Over the last few years we have managed to reduce cost by more than 20 percent. As a consequence, DEA has got the opportunity to open a new area in the Norwegian Sea for gas production and export”, says Andreae.
The Dvalin field is located in PL435, blocks 6507/7/9 and 6507/8 in the Norwegian Sea, approximately 15 kilometers north west of Heidrun and 290 kilometers from Nyhamna in Mid-Norway.
DEA Norge is operator of license PL435 with a 40% share. Partners are Edison (20%), Maersk (20%) and OMV (20%)*. The development is subject to the approval from the Norwegian authorities.
Dvalin – a stag in the tree of life
When a Norwegian oil and gas field enters the development phase, it will change name according to official guidelines.
In the area of license PL435 it is an established tradition to give the fields names from Norse mythology. The nearby field Heidrun is named after the goat that grazes on the roof of Vallhalla, a majestic, enormous hall located in Åsgard, ruled over by the god Odin. Yggdrasil is an immense ash tree that connects the nine worlds in Norse mythology. Dvalin is one of four stags that grazes off the leaves of Yggdrasil.
*OMV Norge AS has entered into a sale and purchase agreement with Petoro AS, under which Petoro AS will be assigned a 20% working interest in the Dvalin-license (PL 435) from OMV Norge AS. The agreement is subject to approval by the General Assembly of Petoro AS and Governmental approval.
DEA has now awarded the EPCI (Engineering, Procurement, Construction and Installation) contract for the smaller structures and pipelines as well as the subsea installation work of the Dvalin development to Technip Norge AS.
The contract includes the fabrication of smaller structures, the 12/16-inch pipe-in-pipe production flowline, the 12-inch gas export pipeline and the installation of pipelines as well as all subsea structures and umbilical for the Dvalin field.
“This contract is another major element for the Dvalin field development. We will now start to collaborate closely on the details with all companies we have on board, to continue the efficient work on the project”, says Hans-Hermann Andreae, Managing Director of DEA Norge.
“The Dvalin license has awarded contracts with a value of 530 million EUR (4.5 billion NOK) over the past days. These contracts will create hundreds of jobs in a demanding time for the supplier industry”, says Andreae. Later in the project phase, several other contracts will be awarded, among others a contract for the drilling of four production wells.
The development cost is estimated to 1.1 billion Euros (10 billion Norwegian Kroner), with planned production start in 2020. Dvalin will be developed with a four wells subsea template, which is connected to the Heidrun platform. At Heidrun, the gas will be partly processed in a new module, before the gas is transported in a new export pipeline to Polarled, going to the Nyhamna onshore gas terminal. At Nyhamna, the gas will be processed and transported to the European market.
Recoverable reserves of the Dvalin field are estimated to around 18.2 billion cubic meters gas and 0.4 million cubic meters of condensate. The field is located in PL435, blocks 6507/7/9 and 6507/8 in the Norwegian Sea, approximately 15 kilometers north west of Heidrun and 290 kilometers from Nyhamna in Mid-Norway.
As human beings, we are creatures of habit. We quickly adapt to routines and like things a certain way, ordering our favourite dish off the menu to avoid disappointment for example. The same can perhaps be said of the oil and gas industry. We know this is a cyclical industry with peaks and troughs. For the past two years, we have been stuck in the trough part of the cycle, as oil prices have gone through a period of volatility. Still, at every level of an organization, we all need to focus on what we can control. Only then can we navigate through this challenging time and emerge stronger. As an industry, we need to increase efficiency while maintaining safety and keeping costs under control.
Great steps have been made through advances in technology and the introduction of digital industrial solutions, however the potential to improve productivity further remains vast. One challenge that equipment manufacturers face in the oil and gas industry is the differing engineering standards and product specifications of end users. Each operator on the market has its own customized standards by which it works.
Embracing manufacturing standardization, particularly during a down-cycle period—such as the one we’re in now—would lead to higher-quality products, better productivity, increased reliability, shorter delivery time and most importantly, lower costs.
A lack of industry-wide standardization means that a large amount of time and money is spent tailoring solutions to each customer’s specific requirements. For example, the aviation industry has benefited heavily from industry-wide standardization—it is regulated in such a way that all manufacturers must comply with centralized FAA standards. This means that when an aircraft manufacturer purchases an engine, they know they’re getting a product that meets industry-wide regulations.
Operators, OEMs and partners are looking at new ways to achieve a unified goal—keeping costs under control, mitigating risks and injecting speed and efficiency in the industry for the long term. From innovative commercial models to closer partnerships and new collaborative frameworks from the early stages of a project life cycle, there is a lot going on in this sector. Designing and implementing manufacturing standards would further benefit both end users and providers alike, bringing a number of advantages, such as:
The low oil price environment has put pressure on the industry to drive down cost. Now is the time for the industry to come together, agree on standards and simplify the way we work. If that were to happen, we could all benefit during a future upturn in the oil price. If you wish to continue this conversation, please visit the online community Tech Talks.
By Luca Passaleva, Oil & Gas Commercial Director, GE’s Marine Solutions
Bureau of Ocean Energy Management (BOEM) Director Abigail Ross Hopper has announced that the bureau will offer approximately 47 million acres offshore Louisiana, Mississippi, and Alabama for oil and gas exploration and development in a lease sale that will include all available unleased areas in the Central Planning Area (CPA).
Proposed Central Gulf of Mexico Lease Sale 247, scheduled to take place in New Orleans in March of 2017, will be the twelfth offshore sale under the Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program). This sale builds on eleven sales, already held in the current Five Year Program, that have netted more than $3 billion, and supports the Administration’s goal of continuing to increase domestic oil and gas production.
“As one of the most productive basins in the world, the Gulf of Mexico remains a critical component of the Administration’s domestic energy strategy to create jobs, foster economic opportunities, and reduce America’s dependence on foreign oil,” Hopper said. “The exploration and development of the Gulf of Mexico’s vital energy resources will continue to help power our nation and drive our economy.”
Sale 247 will include approximately 8,878 blocks, located from three to about 230 miles offshore, in water depths ranging from 9 to more than 11,115 feet (3 to 3,400 meters).
“The decision to move forward with plans for this lease sale follows extensive environmental analysis, public comment and consideration of the best scientific information available,” said Hopper. “This proposed sale is another important step to promote responsible domestic energy production through the safe, environmentally sound exploration and development of the Nation’s offshore energy resources.”
The proposed terms of this sale include conditions to ensure both orderly resource development and protection of the human, marine and coastal environments. These include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species and avoid potential conflicts associated with oil and gas development in the region. BOEM’s proposed economic terms include a range of incentives to encourage diligent development and ensure a fair return to taxpayers. The terms and conditions outlined for Sale 247 in the Proposed Notice of Sale are not final. Different terms and conditions may be employed in the Final Notice of Sale, which will be published at least 30 days before the sale.
All terms and conditions for Central Sale 247 are detailed in the Proposed Notice of Sale information package, which is available here. Copies of the PNOS maps can be requested from the Gulf of Mexico Region’s Public Information Unit at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).
The Notice of Availability of the Proposed Notice of Sale will be available tomorrow for inspection in the Federal Register here and will be published in the September 16, 2016 Federal Register.
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