ENGIETODAY FRESH FACTS FROM ENGIE E&P NORGE | ISSUE NUMBER 1, AUGUST 2016
Future connections PAGE 2
Record high gas production on Gjøa
ENGIE developed oil app for offshore inspections
By continually challenging limitations and spotting potential, ENGIE E&P has increased the current gas production from Gjøa in the North Sea by 17.5 per cent.
ENGIE E&P Norge has developed a mobile solution for offshore pipe inspections. The app will save the company millions of Norwegian kroners and reduces paperwork.
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TODAY’S INSIGHT
Future connections T
he North Sea still surprises with new possibili ties. By combin ing strong operational performance, cost control and expe rience, ENGIE E&P will further strengthen its position in this region, says Cedric Osterrieth, Managing Director of the Norwegian affiliate. The oil and gas company ENGIE E&P, formerly known as GDF SUEZ E&P, recently announced a strategic shift to refocus its activities in Northern Europe and the Mediterranean.
This ambition is built on the company’s strong historical position and will make full benefit of its operational base. – Activities in The North Sea and the Norwegian Sea will play a significant role for the company going forward. These are our core areas, in which we aim to further explore and as the case may be add third party tie in to make best use of our infrastructure, says Osterrieth. ENGIE E&P Norge is present in all three areas on the Norwegian shelf, both as an operator and partner. The company is involved with different types of development solutions: Floating platforms on Njord (Norwegian Sea) and Gjøa (North Sea), onshore facility on Snøhvit in the Barents Sea,
subsea facility on Fram (North Sea) – and a platform resting on the seabed for Gudrun (North Sea). In addition, the company takes an active part in two development projects in the Norwegian Sea (Njord Future and Snilehorn). In total, the company’s portfolio consists of 45 licenses, including 22 exploration licenses. This year, the company will take part in three exploration wells, of which one as an operator. Gjøa as key infrastructure Since start-up in 2010, the ENGIE E&P Norge-operated Gjøa platform in the northern part of the North Sea, has had outstanding results both on production as well as on
“Activities in The North Sea and the Norwegian Sea will play a significant role for the company going forward. These are our core areas, in which we aim to further explore and as the case may be add third party tie in to make best use of our infrastructure.” CEDRIC OSTERRIETH
Last edited August 2016. Editor in chief: Liv Jannie Omdal, Leader Communication. Contact communication department: press@no-epi.engie.com ENGIE E&P Norge AS, Vestre Svanholmen 6, Sandnes, P.O. Box 242, 4066 Stavanger, Norway. www.engie-ep.no. Design by Melvær&Co. Print: Spesialtrykk. Photos by: Jan Inge Haga, Koen Vlaeminck, Antoine Meyssonnier and Transocean.
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Responsible growth – at the heart of our business The ENGIE Group has put responsible growth at the heart of its electricity, natural gas and energy services businesses to rise to the major challenges of the energy transition to a low-carbon economy. Access to sustainable energy, alleviating and adapting to climate change and the rational use of resources, are all examples of challenges in which the energy world need to find solutions. A green transition To meet the expectations of its stakeholders, the ENGIE Group has presented a transformation plan gradually moving the Group towards a world of decentralized energy solutions, renewables, digital solutions and greener gas. – The Group will focus on decentralized and greener gas solutions. In this picture, enhanced customer services and the development of digital technologies that enable the adjustment of energy production according to use, will also play a major part in reaching our goals, says CEO Maria Moræus Hanssen in ENGIE E&P.
Near-field development: ENGIE E&P Norge aims to be sustainable at lower hydrocarbon prices. Going forward, we will focus even more on near-field exploration and business development in core areas, says Managing Director Cedric Osterrieth.
operational performance. To date in 2016, Gjøa runs with a production regularity above 98 per cent, and has increased the gas export rate to 20 MSm³/d, 17.5 per cent more than estimated. – Due to good reservoir management, Gjøa is set to produce 60 million barrels of oil equivalents more than estimated at start of production. Yet, it still has capacity to handle extra resources. The fact that the platform is operated with power from shore, reducing CO2 emissions, makes it an attractive hub for the area, says Osterrieth. The semi-submersible production unit has full processing and export capabilities. Oil is exported to the Mongstad crude oil terminal.
Export of gas ends up at the St. Fergus gas terminal in Scotland. Gjøa is offering capacity to operators for surrounding fields, and is currently in dialogue with the Skarfjell license regarding a potential tie in of the discovery. Cost-effective operations ENGIE E&P Norge continues to capture cost reductions and efficiency gains. In 2015, two cost saving programs were initiated, resulting in 15 per cent reduction on cost base. – ENGIE E&P Norge aims to be sustainable at lower hydrocarbon prices. Going forward, we will focus even more on near-field exploration and business development in core areas, says Osterrieth. Cost initiatives on operated
activities will be high on the company’s agenda. The company aims to bring the cost basis down by about 20 per cent in 2017 compared to 2014. – This tells us we are on the right track in becoming an even more attractive operator and partner on the NCS, says Osterrieth.
Gas plays a key role In the transition to a low carbon energy mix, gas plays a key role. ENGIE E&P will increase its efforts to produce and promote natural gas and LNG to countries, customers and industry as a replacement for higher polluting fuel sources. Today, gas amounts to more than 60 per cent of ENGIE E&P’s total production. In addition, it is currently the third largest seller of natural gas in Europe.
ENGIE AND NATURAL GAS/LNG
1st
5th
seller of gas storage capacity in Europe
LNG portfolio in the world
2nd
1st
gas transmission network in Europe
importer of LNG in Europe
1st
2nd
gas distribution network in Europe
largest gas terminal operator in Europe
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TODAY’S RECORD
Record-high gas production at Gjøa Gjøa was originally designed to export 17 million standard cubic metres of gas per day (MSm³/d). That we are currently producing 20 MSm³/d, 17.5 per cent more than estimated, is a great achievement. HILDE ÅDLAND
By continually challeng ing limitations and spot ting potential, ENGIE E&P has increased the current gas production from Gjøa in the North Sea by 17.5 per cent. Moreover, Gjøa is scheduled to produce 60 million barrels of oil equivalents more than estimated at start of production. – Gjøa was originally designed to export 17 million standard cubic metres of gas per day (MSm³/d). That we are currently producing 20 MSm³/d, 17.5 per cent more than estimated, is a great achievement, says Hilde Ådland, Head of Asset Gjøa and Vega in ENGIE E&P Norge AS. Increased earnings by nok 5 million per day The last milestone on the road to increased gas production was reached on 7 March this year, when Gjøa produced 20 MSm³ per day for the first time. The improvement from 17 to 20 MSm³ has increased gas export revenues by NOK 5 million per day for the Gjøa licence, calculated in current day prices. – Going from a limited export level of 10.5 MSm³/d due to singing risers in 2010, to the current production level has been an exciting process. We have continually focused on challenging limitations and
trying to find solutions, which has yielded good results. Now that we’ve achieved 20 MSm³/ day, it is an extra bonus that we’re also experiencing a regularity of 98.3 per cent, says Ådland. Extended lifetime by 60 mboe The increased production does not affect safety in any way, but the daily operations are monitored even closer. From ENGIE E&P’s office in Stavanger the company has access to all systems at Gjøa. By conducting daily video conferences with the platform and weekly meetings with other suppliers to the gas export pipeline (FLAGS), ENGIE E&P in Norway are now even more ‘hands on’ with production than previously. – Due to good reservoir management, Gjøa is set to produce 60 million barrels of oil equivalents more than estimated at start of production, and in total, the field will produce 400 million barrels of oil equivalents over its lifetime, says Ådland. ENGIE E&P Norge AS aims to be sustainable at lower hydrocarbon prices. A greater focus on costs has reduced the operating expenses on Gjøa by 10 per cent from 2015 to 2016, and the company is already working on reducing this further in 2017.
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Did you know that •G jøa represents one of the largest development projects on the Norwegian Continental Shelf the previous decade •G jøa was the first oil and gas field that came on stream in the northern part of the North Sea •G jøa is a semi-submersible floating production platform, which was delivered on time and on budget •G jøa is the first floating platform operating with power from shore – through a 100 km long submarine cable from Mongstad •E lectrification of the Gjøa field reduces CO2 emissions by 200 000 tons a year. This corresponds to the emissions from 100 000 cars •G as from the Gjøa field represents daily consumption of around 1.5 million European households •G jøa is the seventh highest producing field on the Norwegian Continental Shelf, on average around 100 000 barrels of oil equivalent daily •S ince startup the Gjøa platform has had good HSE results and high regularity on production Teamwork: Great teamwork both on board Gjøa and with onshore colleagues is necessary to succeed. From left: Process Technician Oliver Tømmernes and Operations Technician Lars Westbye.
•O ur platform base is located in Florø, Sogn og Fjordane county. 30% of purchases related to Gjøa operations are bought locally • The Gjøa platform is a state of the art production installation with pioneering use of integrated operations
FACTS: ENGIE E&P Norge AS holds shares in 45 licenses on the Norwegian Continental Shelf. The company is operator of the producing field Gjøa, and of seven exploration licenses. Net production from the Gjøa field in 2015 was 12.6 million barrels of oil equivalent (boe) – making Gjøa the seventh largest producer on the Norwegian Continental Shelf (NCS). The company’s ambition is to offer attractive technical solutions for third party business to Gjøa, as well as optimizing value of portfolio in core areas: Gudrun (North Sea), Gjøa (North Sea) and Njord (Norwegian Sea), and Snøhvit (Barents Sea). The license partners in PL 153 Gjøa are ENGIE E&P Norge AS (Operator, 30%), Petoro AS (30%), Wintershall Norge AS (20%), A/S Norske Shell (12%) and DEA Norge AS (8%).
Proud: Head of Asset Gjøa and Vega, Hilde Ådland, is proud of the employees’ dedication to improve production in a safe and sound manner.
Ambitious: ENGIE E&P Norge has always had high ambitions for the Gjøa platform – both in regards to HSE and production results.
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TODAY’S TECHNOLOGY
Exploring the Gjøa area Summer 2016: The Transocean Arctic drilling rig on the way to Cara in the North Sea.
During the summer 2016, ENGIE E&P Norge has been drilling the Cara exploration well in the North Sea. ENGIE E&P Norge is the operator of the exploration well PL 636 Cara, which is located 35 kilometres from shore and approximately 6 kilometres from Gjøa in the Northern North Sea.
a four string casing program. The well was spudded on 18 July by the drilling rig Transocean Arctic which is conducting the drilling operation. The Transocean Arctic, operated by Transocean Norway Operations AS, is a harsh environment midwater semi-submersible drilling rig. The drilling operation is scheduled to take approximately
“The results from Cara will increase our understanding of the Gjøa area, which is one of our core areas on the Norwegian Continental Shelf.” CEDRIC OSTERRIETH
The water depth is about 350 metres and both oil and/or gas cases are considered. The well is regarded a standard exploration well of conventional design with
41 days. In case of discovery, the plan is to execute a Drill Stem Test for an additional 25 days to assess the size of the reservoir.
– In case of a commercial discovery, Cara is a potential tie-back to the Gjøa-platform, which we operate. The results from Cara will increase our understanding of the Gjøa area, which is one of our core areas on the Norwegian Continental Shelf, says Cedric Osterrieth, Managing Director of ENGIE E&P Norge. The Norwegian Petroleum Directorate will announce the result of the drilling operation.
LICENSE PARTNERS IN PL 636: ENGIE E&P Norge AS (30% and operator) Idemitsu Petroleum Norge AS (30%) Tullow Oil Norge AS (20%) Wellesley Petroleum AS (20%)
Florø
CARA WELL
GJØA FIELD
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Do I jump when the alarm sounds? No, I have plenty of time to fix the problem. PER KRISTIAN ROALD
Monitoring: Senior Subsea Engineer Per Kristian Roald monitors subsea templates with his smartwatch.
Subsea monitoring around the clock Well before a critical fault occurs in the subsea equipment on the Gjøa platform in the North Sea, an alarm will sound on the smart watch around the wrist of senior subsea engineer Per Kristian Roald in ENGIE E&P Norge. – Do I jump when the alarm sounds? No, I have plenty of time to fix the problem, says Roald with a smile. The subsea engineer works on monitoring and remote diagnostics for the five subsea templates tied in to the Gjøa platform, 60 kilometres west of Florø on the western coast of Norway. The goal is to maintain control over the facility’s integrity and to detect faults and weaknesses in the subsea equipment before they turn into bigger problems. On his computer, Roald has real-time monitoring that analyses trends and provides feedback on recommended actions to prevent interruptions in production. Unplanned repair and maintenance can cost millions of kroner. It is Roald’s job to prevent this from happening. His job is quite unique in the industry.
ENGIE was first As one of the first oil and gas companies in the world, ENGIE E&P has used a new technology called Condition and Performance Monitoring (CPM), since 2012. The technology was developed by FMC Technologies. CPM collects raw data from the subsea equipment. This data is calculated, simulated and analysed to generate the most
made. Now it takes 25 minutes to find the fault, says Roald. The screen on his computer shows folders, graphs and flow diagrams. The colour code in the graphs will change if there are any changes in equipment ranging from valves to pumps – changes which could create issues in a few months. And the alarm on Roald’s smartwatch will sound.
Smartwatch: Well before a critical fault occurs in the subsea equipment, an alarm will sound on the smartwatch.
complete picture possible of how the equipment behaves in real-time at a water depth of 360 metres. – We previously had to send engineers out to the platform to collect the same information. It could then take several months before a diagnosis was
Better maintenance planning The development of CPM has been ongoing for several years, and it can be used offshore, onshore and by suppliers. The system collects necessary data from existing sensors and equipment. The data is converted into a decision basis
via a complex system. This saves ENGIE E&P time and money: – The trend analyses function in CPM is an excellent decision-making tool. It allows us to make the most efficient decisions along with the contractor. ENGIE E&P can then plan subsea campaigns and interventions during periods with other planned maintenance. As a small operator, we have less access to vessels, and the work should preferably take place in a good weather window, says Roald. Significant savings A subsea intervention in Norway costs between NOK 15-20 million. Since the system was put to use, ENGIE E&P has reduced the number of ad hoc repairs subsea and has not experienced an unplanned shut down of production. – It is said that CPM was made so the operations engineers can sleep well at night. I think this rings true for a lot of people, says Roald with a smile.
PREVENTED SHUT DOWN WELL AND COSTLY REPAIR E-1 is the name of the best gas producer on the Gjøa field. The subsea monitoring system detected a fault that would normally have been extremely costly to repair. Production has been virtually uninterrupted since start-up. The barriers against the reservoir and well consist of several valves. They must be regularly tested and checked. If control over the barriers is lost, production must be shut down. In 2014, one of the valves on E-1 broke down. Normally, this incident would have caused the well to be shut down for a long time, and repair costs were estimated at about NOK 500 million. However, production can continue because ENGIE E&P can document the condition of the second barrier through the CPM subsea monitoring system, and will thus be notified before a potential fault occurs.
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TODAY’S INNOVATION
ENGIE developed oil app for offshore inspections
E
NGIE E&P Norge has developed a mobile solution for offshore pipe inspections. The app will save the company millions of Norwegian kroners and reduces paperwork. The EMIS app (ENGIE Mobile Inspection Solution) was recently put to use on the ENGIE-operated Gjøa platform in the North Sea. The number of inspected pipes is expected to double and the company will
achieve potential savings of about 5-10 million Norwegian kroners a year from improved efficiency and risk scenarios. In addition, this could save the
on reporting. Overall, this has generated 500 pages of written reports each year. – This has been completely reversed through use of tablets
“Inspectors can now spend 80 per cent of their time inspecting and just 20 per cent sitting in front of the computer to work on completing documentation.”
and the EMIS inspection app. Inspectors can now spend 80 per cent of their time inspecting and just 20 per cent sitting in front of the computer to work on completing documentation, says Unni Ulland, Manager ICT in ENGIE E&P Norge. She stresses that EMIS contributes in the work to digitalise offshore work on The Norwegian Continental Shelf. Data is available immediately The Ecom tablets produced by HawCom are among the first in
the market certified for offshore use in Zone 1. Until now, mobile network solutions have not been permitted in Zone 1, due to safety requirements in areas with an explosion risk. The tablets that can now be used provide access to inspection data along with work orders, which increases work flexibility. Many of the pipes are located in difficult to access locations, near the ceiling, over the water and between other pipes. The tablets enable the inspectors to take photos and note potential
UNNI ULLAND Inspection: There are about 2000 SS316 pipes, which corresponds to 23 kilometres, to inspect on the Gjøa platform.
company for replacement of pipes, with costs of at least 100 000 NOK per meter. 23 km of pipes to inspect There are about 2000 SS316 pipes on the Gjøa platform, which corresponds to 23 kilometres of pipes. Regular inspection of these pipes is crucial to uncover degradation, corrosion and damage. So far, inspectors have spent 20 per cent of their time offshore on inspecting, and 80 per cent
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damage to the pipes. – The inspection results are saved online and are immediately available for analyses and decision-making for onshore engineers. This process previously took up to two weeks, says Arne Bekkeheien, Leader Mechanical and Maintenance in ENGIE E&P Norge. As a result of the number of inspections having doubled, inspectors now have time to examine pipes that were not previously prioritised. – Using the tablet and app, we can detect potential damage before this develops into a larger problem. This could save us
from having to replace pipes, which is very costly. Safety is also improved, says Bekkeheien. Will pay for itself within six months The app was developed by the ENGIE E&P Norge oil and gas company in cooperation with the Bouvet IT company, over the course of about one year. It has cost the company about NOK 2.5 million Norwegian kroner. – As far as we know, this is the first time tablets and an app are used offshore like this. The system is scalable and is under consideration for use in other operations and maintenance tasks on the Gjøa platform, says Bekkeheien.
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Saving time: So far, inspectors have spent 20 per cent of their time offshore on inspecting, and 80 per cent on reporting. This has been completely reversed through use of tablets and the EMIS inspection app.
The inspection results are saved online and are immediately available for analyses and decision-making for onshore engineers. This process previously took up to two weeks. ARNE BEKKEHEIEN
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TODAY’S CORPORATION
Norway and ENGIE – long-term gas connections
Optimising value in core areas
Snøhvit The first and only LNG production facility in Europe. ENGIE’s production from the LNG plant is being lifted onto the ENGIE Group’s LNG tankers. In 2015, the company lifted eight cargos and similar numbers are expected in the years to come.
ENGIE E&P Norge’s strategic objective is to optimise value of portfolio in our core areas additional to the Gjøa area: Gudrun (North Sea), Fram (North Sea), Njord (Norwegian Sea), and Snøhvit (Barents Sea).
SNØHVIT
By being an active partner in the licenses, an initiator of state of the art technical solutions and seeking new opportunities through upcoming Awards in predefined areas (APA) – our ambition is to be a driving force in increased value creation on the Norwegian Continental Shelf.
Gross remaining recoverable reserves (YE2015) • 2P: 1154 MBOE (84% gas), produced 289 MBOE • Plateau design: 4.3 mtpa LNG (2011->)
NJORD
GJØA FRAM
GUDRUN
License and ownership Awarded 1981 and discovered 1984 Statoil: 36,79% (Operator) ENGIE E&P Norge: 12% Partners: DEA, Total, Petoro
Development • Three gas field in a phased subsea development with 150 km multiphase pipeline to shore • CO2 removal and re-injection • LNG-train with 20.8 MSm³/d feedgas capacity • Currently producing from Snøhvit and Albatross fields; 9 producers + 1 CO2 injector • New CO2 injector (G-4H) sanctioned in 2013. To be drilled in 3Q 2016 • Snøhvit infill well (F-1H) and Snøhvit Nord (G-3H) sanctioned 2015. To be drilled in 2016 and 2018, respectively • Askeladd to be next plateau extender with tentative start up in 2020
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B
uying natural gas, own produc tion of oil and gas on the Norwe gian Continental Shelf – the connections between Norway and ENGIE are many. The ENGIE Group has been buying natural gas from Norway since 1977 (Ekofisk) and is today one of the largest buyers of gas from the Norwegian Continental Shelf. In 2015, 26 per cent of the ENGIE Group’s portfolio of third party long-term contracts on gas came from Norway, making Norway the largest contributor to the Group’s long-term portfolio of gas supply.
“Our ambition is that gas will play a more prominent role in our portfolio in the future.” CEDRIC OSTERRIETH
ENGIE GROUP THIRD PARTY LONG-TERM GAS CONTRACTS
26% 26% Norway 20% Russia 15% Algeria 11% Netherlands 6% Asia 5% Trinidad & Tobago 3% Lybia 2% Nigeria 1% Australia 1% Yemen 1% Others 9% Unspecified
Equity production In addition to being a large buyer of gas, the company established its own affiliate for oil and gas production in Norway in 2001, today called ENGIE E&P Norge. In 2015, ENGIE E&P Norge accounted for 58 per cent of the ENGIE Group’s total oil and gas production. About 52 per cent of the affiliate’s production was natural gas. In the transition to a low carbon society, the ENGIE Group sees gas playing a key role.
ENGIE E&P OIL AND GAS PRODUCTION 2015
ENGIE E&P 2P RESERVES AT END 2015
58%
40%
58% Norway 25% The Netherlands 11% Germany 3% United Kingdom 3% Other
ENGIE will therefore increase its efforts to promote natural gas and LNG to countries, customers and industry as a replacement for higher polluting fuel sources. – In this perspective, our ambition is that gas will play a more prominent role in our portfolio in the future, says Cedric Osterrieth, Managing Director of ENGIE E&P Norge. The Norwegian affiliate is also the largest contributor to the ENGIE Group’s oil and gas reserves (2P), of which it holds 40 per cent.
40% Norway 30% Other 13% Germany 10% The Netherlands 7% United Kingdom
Origin of the equity production ENGIE E&P Norge is operator of the Gjøa field and partner in the Njord, Snøhvit, Fram and Gudrun fields. The Gjøa field is the company’s flagship with an average production of 100,000 barrels of oil equivalents (boe) per day. It is the seventh highest producing field on the Norwegian Continental Shelf.
Njord
Fram
Njord is an oil and gas field which started production in 1997, initially re-injecting produced gas. In 2006, Njord started exporting gas and in 2013 3rd party Hyme subsea field was tied in to Njord. Due to structural issues, the Njord facilities were towed to shore summer 2016. The plans are to repair the platform and return to the field for start-up in Q4 2020. In parallel, 3rd party Snilehorn discovery is planning for tie-in to Njord in the same period.
Fram is a subsea field consisting of two main structures; West and East developed in 2003 and 2006, respectively. The field is tied back to Troll C for processing and transport.
License and ownership (PL107/PL132) Awarded 1985/1987, discovered 1986 Statoil: 20% (Operator) ENGIE E&P Norge: 40% Partners: DEA, Faroe, VNG Gross remaining reserves and production (YE2015) ~105 MBOE, produced 245 MBOE Development • Semi-submersible platform with subsea completed wells, 18 slots and 15 risers • Capacity: 10.1 MSm3/d gas and 12,000 Sm/d oil • 6 active wells: 5 producers and 1 gas injector before shut down June 2016 • Gas export via Åsgard T, offshore storage and offloading of oil • Shut in July 2013 to July 2014 for structural reinforcement Redevelopment Project • Njord A & B to shore for repair during summer 2016 • Njord Future Project – Concept Selection July 2016 • Sanction expected Q1 2017 • Planned return of Njord to production Q4 2020 • Snilehorn tie-in and sanction
License and ownership PL090 awarded 1984, discovered 1990 Statoil: 45% (Operator) ENGIE E&P Norge: 15% Partners: Exxon and Idemitsu Gross remaining reserves and production (YE2015) 2P: 94 MBOE (40% gas), produced 229 MBOE Development • Subsea development with tie-in to Troll • Fram West: Gas injection; 4 OP + 1 GI • Fram East: Water injection; 5 OP + 2 WI • Spare slots for further area development • H-Nord, 3rd party tie-back, started production September 2014 • C-East planned drilled 3Q 2016 • Astero (3rd party) development planned for 2017 start-up NOTE: OP=Oil producer, GI=Gas injector, WI=Water injector
ENGIE E&P NORGE NET PRODUCTION 2015
ENGIE E&P NORGE
Gjøa 12.6 million boe Njord 4.5 million boe Fram 2.1 million boe Snøhvit 5.8 million boe Vega Unit 0.6 million boe Hyme 1.3 million boe Gudrun 8 million boe H-North 0.2 million boe
LNG ENGIE owns 12 per cent in the Snøhvit field and LNG (Liquid Natural Gas) production facility. The company’s production from the facility is being lifted onto the ENGIE Group’s LNG tankers. In 2015, the company lifted eight cargos and similar numbers are expected in the years to come. The last years’ cargoes have been delivered in Europe, the Americas and Asia.
Gudrun
High Pressure High Temperature (HP/HT) project delivered on time, below cost and with no serious HSE incidents. Tied back to Sleipner with production start April 2014. License and ownership • PL025 awarded 1969, discovered in 1975 • Statoil: 36% (Operator) • ENGIE E&P Norge: 25% Partners: OMV, Repsol Gross recoverable reserves (YE 2015) • 2P: 91 MBOE (33% gas share), produced 42 MBOE Development concept • Partial processing platform (jacket) at Gudrun with tie-in to Sleipner for further processing and CO2 removal • 7 production wells • Capacities: 12000 Sm³/d of oil and 6 MSm³/d of gas
FACTS AND FIGURES Gjøa – North Sea hub
Gjøa – the numbers hero
60 kilometres west of Florø
Ideal area hub for gas en route to Europe
Lifetime production of 400 million boe
Offering capacity
Cost-efficient solution
60 million boe more than first estimated
Land-based power – lower cost
98.3% regularity
FLORØ
ST. FERGUS
MONGSTAD GAS
Gjøa is the 7th highest producer on the NCS. Net production 2015: 12.6 million boe
OIL
Gjøa is electrified – power supplied from Mongtad
An active partner and operator Shares in 45 licenses on the NCS
Operator of Gjøa
Cutting annual CO2 emissions by approx. 200 000 tonnes
Equivalent to 100,000 cars!
ENGIE 2015 net production Operator of seven exploration licenses
Gjøa 12.6 million boe
Njord 4.5 million boe
Fram 2.1 million boe
Snøhvit 5.8 million boe
Vega Unit 0.6 million boe
Hyme 1.3 million boe
Gudrun 8.0 million boe
H-North 0.2 million boe