DOF Subsea Inks Transmediterranean Pipeline Survey Contract

9DOF Geosund full size 2 copyDOF Subsea, a leading provider of integrated subsea services, has recently inked a new contract in the Mediterranean with Transmediterranean Pipeline Company Limited (“TMPC”) to undertake the pipeline inspection on the TMPC’s Pipeline System in Q3, 2017.

The scope involves inspection of 5 submarine pipelines between Sicily and Tunisia and during the scope, DOF Subsea will survey over 750 km of pipeline.

DOF Subsea will deploy the high specification survey vessel, MV Geosund to complete the inspection work scope and pipeline intervention.

DOF Subsea successfully completed a similar scope for TMPC in 2014.

Managing Director, Robert Gillespie said “We are delighted to win this work with TMPC. We have a good relationship with the company, having successfully completed this inspection scope for them in the past, and we are looking forward to delivering on this scope again later this year.

DOF Subsea has an extensive track record in Survey and IMR; combined with our high-specification fleet of owned vessels and skilled ROV and Survey teams, we are able to offer fully integrated solutions for our clients’ projects”.

M-Tech Offshore’s DP-2 Cable Laying Vessel, CLV SIA

10CLV SIAM-Tech Offshore A/S, is a Danish joint venture company equally owned by NT Offshore A/S and Maritech International LTD, owning and operating the CLV SIA, an efficient handy-sized DP-2 cable laying vessel, which is configured for worldwide inter-array and subsea power cable installations and maintenance, with additional facilities on-board to accommodate for installation of smaller subsea cables, including fibre-optics.

The CLV SIA flies the Danish flag, is a fully SOLAS classed vessel, equipped with efficient cable lay spread, 3 turn-table cable tanks, deck winches, A-frame & cranes and accommodates SIMEC's work-class trenching ROV "Seagma", suitable for inspection, survey and burial operations on up to 3m trenching depth, on maximum operating water depth of 1000m.

Additional modular deck spreads are also available for support operations such as pre-lay grapnel runs and route clearances. The 500m2 vessel's deck has been strengthened for LARS, making it an ideal ROV support platform, whist the on-board survey electronic spread, moon-pool and side mounted equipment can be utilised for cable route survey operations.

In addition to cable laying capabilities, the CLV SIA has modern and comfortable accommodation for 50 passengers with crew and can be utilised as a multipurpose support vessel, capable of handling challenging environmental conditions.

Acquisition and subsequent upgrade of the CLV SIA follows the 2016 announcement that Maritech International LTD with NT Offshore A/S had formed the Joint Venture company M-Tech Offshore A/S. Maritech's 25 years of experience in the subsea cable industry, coupled with NT's long-term presence in the North Sea, is now backed by a strategically positioned vessel management office in Esbjerg, Denmark.

Gas Safety Top of the Agenda for Martek Marine on US $3 Billion Offshore Project

Maritime industry technology specialists Martek Marine are setting the bar high when it comes to offshore gas safety. The company has developed a first-of-its-kind gas sampling system for a new moored floating production unit, which forms part of the Jangkrik Complex gas fields development in Indonesia. The system has been developed to dramatically improve offshore crew safety through the use of advanced gas sampling technology.

11Gas Sampling System copyA first of its kind gas sampling system. Photo credit: Martek Marine

The worst offshore disaster in history, the Piper disaster on 6 July 1988, involved a series of gas explosions which destroyed the Piper Alpha oil platform in the North Sea, killing 167 men. According to the latest statistics from the Health and Safety Executive, to this day, a third of all dangerous occurrences occurring offshore relate to gas releases. Explosions, following a gas release are a major offshore hazard due to the catastrophic consequences that tend to result; taking life and impacting the health of workers; pollution of the environment; direct and indirect economic losses, and deterioration of the security of energy supply.

Early warning is key when it comes to the prevention of gas explosions. Failure to avoid ignition of released hydrocarbons is best achieved through the installation and functioning of gas detectors in appropriately defined hazardous areas. The offshore accident report ‘Lessons from Past Accident Analysis’ from the European Commission, advises that a vital step in controlling major offshore hazards is the installation of, ‘state-of-the-art gas detectors in appropriate locations, extending to hazardous areas where necessary.’

It’s not then surprising that gas safety was at the top of the agenda for the new, highly-regarded and large-scale offshore engineering project in Indonesia. The Jangkrik Project comprises of the development of the Jangkrik and Jangkrik North East gas fields, referred to jointly as the Jangkrik Complex. Approximately 400m deep, the Jangkrik Complex forms part of the deep-water Muara Bakau block in the offshore Kutei Basin, situated 70km from the coast of East Kalimantan.

Following drilling at three exploration wells, Jangkrik 1,2 and 3, a feasibility study completed in July 2011, led to selection of the most appealing concept for development of the area. The chosen approach is based on a subsea development with 10 wells and full treatment facilities on a spread moored floating production unit (FPU). The FPU has an export line to shore at Sapi Landfall.

In 2014, energy company Eni awarded offshore engineering experts Saipem, the engineering, procurement, construction, and installation contract for the new FPU, valued at US$3 billion. The shipping division of Hyundai Heavy Industries (HHI), who currently hold a 15% share of the global shipping market, built the FPU hull in Ulsan, South Korea, whilst further fabrication work for the topsides was carried out by Saipem in Indonesia, with Saipem’s Execution Centre in Jakarta managing the overall project.

Gaining international interest thanks to the rapid development and short production start-up time, the project has a time to market of just three-and-a-half years from the date of the investment decision and production at the Jangkrik Complex gas fields commences in 2017.

The FPU is designed to process 450 MMcf/d (12.7 MMcm/d) of gas and condensates and is a multi-purpose unit. The Jangkrik gas volumes will supply the local domestic market, the Indonesian LNG market as well as the LNG export market providing a significant contribution to the Country’s energy needs and economic development.

In addition to being used for activities relating to the Jangkrik Complex, the FPU will also act as a hub for other sites nearby. All gas will be sent to a liquefaction plant called Bontang LNG following treatment on board and this is achieved thanks to connections to 10, deep-water subsea production wells. The final destination of all condensate from the site is the Senipah Power Plant in East Kalimantan.

Global maritime technology company Martek Marine specified a gas sampling system for the FPU which is the first of its kind. Based on the company’s well reputed MM5001 Gas Sampling System, the bespoke setup comprises of 4 independent systems. The systems are designed for the sequential sampling of hydrocarbon gas, as well as sequential sampling and continuous monitoring of oxygen. The sampling activities are focused on the ballast and condensate tanks in addition to continuous monitoring of supply headers within the FPU.

"The system will play a vital role in ensuring the safety of those onboard, by giving crew the means to effectively monitor gases within enclosed spaces and ensure that levels maintain within safe parameters." Said Martek Marine Project Engineer, Steve Austwick.

The first sampling system is a split system, designed to sequentially sample hydrocarbon (22 Point) in water ballast tanks. Equipped with the latest dual Non-Dispersive Infra-Red (NDIR) sensors, the equipment is faultless when it comes to monitoring increasing levels of methane (CH4).

Being a split system, the pump, solenoids and sensors are housed in the monitoring side of the system installed in a cabinet on deck. Benefiting from an EExe enclosure and EExd internal components the unit is explosion-proof. The human machine interface (HMI) and programmable logic controller (PLC) are housed control side in the cargo control room (CCR). In a conventional gas sampling system, the control and monitoring equipment is mounted in a single cabinet which is installed in a safe area, usually the CCR.

"The important benefit to a split system, is that the need to run sample piping into the CCR is avoided." Said Austwick.

The second system supplied is a 6-point system used for sequential sampling of oxygen in condensate tanks. In addition to benefitting from the design features of the sequential hydrocarbon gas sampling system, the addition of advanced paramagnetic sensors enables levels of oxygen to be monitored in the inert gas blanket of condensate tanks.

Paramagnetic sensor technology provides unbeaten performance and longevity.

"The sensors use no consumable parts, meaning they excel in terms of durability," said Austwick. "Offering world class precision over a range of 1% to 100% oxygen, they are able to measure the oxygen concentration not only in flammable gas mixtures, but also in low concentrations and with high precision."

Two further gas sampling systems were supplied under the contract, both continuous oxygen gas sampling units. Both single point systems, the first is designed for use in the inert gas supply header and the second, in the high purity nitrogen header.

Both systems benefit from paramagnetic oxygen sensors to monitor oxygen enrichment. Both the sensor and the pump are installed in a single cabinet.

"Having only one sample line ensures the headers are continually monitored and no front-end control is therefore required," said Austwick. "A signal from the system analyser is connected directly to the distributed control system (DCS) on the vessel, ensuring optimum reliability through localised control functions near the equipment."

All gas sampling systems are now installed and the naming ceremony of the “Jangkrik” Floating Production Unit (FPU) vessel took place on March 21, 2017 at Saipem Karimun Yard, Tanjung Balai Karimun, Indonesia. The FPU then sailed to its final destination at the Jangkrik Complex in preparation for gas processing and export, which is expected to reach a capacity of up to 450 million standard cubic feet per day (mmscf/d).

Seatronics Supports Global Oilfield Engineering Services Provider with Key Brazilian Project

12RTS Gen 5 MUX Available from Seatronics1Seatronics, a marine electronic equipment specialist in subsea services group Acteon, has supported a global oilfield provider of engineered services and products, with a key project in Brazil through the supply of state-of-the-art subsea equipment.

Seatronics’ range and expertise provided the company with a single source solution for all its equipment requirements for the project. This ease of service, combined with Seatronics ability to deliver the required range of equipment quickly, fully integrated ahead of delivery, has strengthened the long-standing relationship between Seatronics and their client.

The equipment sale was completed by Houston-based Seatronics Inc and included ROV Survey sensors, which were interfaced to Seatronics exclusive RTS Gen5 MUX ROV multiplexer. All the equipment was connected with Seatronics in house manufactured neoprene cables and the engineered solution was mobilised, system tested and delivered within two weeks to fully comply with the project schedule.

Janelle Totah, Vice President, Seatronics Inc. said: “We are delighted to have been able to support our client with this order.

“This award demonstrates Seatronics continued commitment to supporting clients with their Brazilian operations while the supply of this considerable spread displays our ability to combine industry leading products, cables, and engineering services to deliver top quality solutions for our clients, all from a single source.”

Statoil Awards Contract for New Shuttle Tankers

Statoil ASA and AET, one of the world’s leading petroleum and chemical tanker owners and operators, announce that they are extending their partnership in the North Sea shuttle tanker sector. Statoil has awarded a long-term contract to AET, a subsidiary of Malaysian energy shipping group, MISC Berhad, to operate two specialist DP2 offshore loading shuttle tankers (OLSTs) on long-term charter. These new vessels will be in addition to the two AET DP2 ships currently on charter, in the same area, for Statoil.

13StatoilShuttleTankerThe shuttle tanker Eagle Barents currently on charter for Statoil from AET.

These new vessels are in addition to the two AET DP2 ships currently on charter in the same area for Statoil. The two existing DP2 tankers are owned and operated by AET Sea Shuttle AS (AETSS), a joint venture company formed in 2012 that is also 95% owned by AET and 5% by Norwegian ADS Shipping.

The two twin skeg 125,000dwt tankers will be built by Samsung Heavy Industries for delivery in 2019 and will be contracted to Statoil for operations both in oilfields on the Norwegian Continental Shelf of the North Sea, Norwegian Sea and the southern Barents Sea as well as on the UK Continental Shelf.

Built to a superior specification with a fatigue life based on 30 years of operations in the North Sea, they will be fully capable of working in the harshest of weather conditions. Each will be equipped with winterization features, high power thrusters, shaft generators and the latest generation of bow loading system.

With a focus on energy efficiency, the shuttle tankers will be built with LNG dual-fuel for main and auxiliary engines and also an option to be fitted with a volatile organic compound (VOC) recovery system. Other environmental innovations will maximize fuel efficiency and minimize emissions. When in operation from 2019, these two DPSTs are expected to be the world’s first LNG fueled DPSTs and most energy efficient.

“Statoil is pleased to award this contract to AET and their partners and thereby deepen and increase our cooperation within shuttle tanker operations. The agreed newbuild state-of-the-art DP2 shuttle tankers will strengthen Statoil’s position for safe, efficient and cost competitive transportation of offshore loaded crude oil production to our customers. The fuel efficiency features built into these vessels, including LNG duel fuel capabilities, will significantly reduce operational costs and climate emissions. As such this contract is strongly aligned with Statoil’s sharpened strategy,” says Statoil’s senior vice president for asset management in Marketing, Midstream and Processing, Grete Birgitte Haaland.

Captain Rajalingam Subramaniam, chairman, AET Sea Shuttle AS (AETSS) and president & CEO, AET, said:

“We first forged a partnership with Statoil in 2012 when we were awarded a long-term contract to operate two state-of-the-art shuttle tankers in the North and Barents Sea. I am delighted that Statoil has recognized and endorsed the quality of our operations in this most demanding of environments by giving us a further opportunity to support their business with two additional state-of-the-art DPSTs. We believe, as part of the MISC Group, our strategic partnership and our innovative solutions gave us the edge over other operators in the North Sea. Statoil is global leader in this region and I am confident that we will deliver on the trust they continue to place in our capability to deliver flawless operations in this challenging region. We are proud to be extending our partnership with this world leading oil company.”

In 2012, AET formed a joint venture company - AET Sea Shuttle AS - 95% owned by AET and 5% owned by Norwegian ADS Shipping, to own and operate two North Sea DP vessels. The two new ships will also be owned and operated by the same joint venture partners. OSM Maritime Group will provide the lead technical management, supported by the MISC Group, during the newbuilding.

ADS and OSM group chairman, Bjørn Tore Larsen said:

“This is a great opportunity for us to extend our successful partnership with AET. We have been operating in this region for many years and extending the joint venture cements our relationship both with AET and Statoil. I firmly believe that the combination of technical, operational and commercial skills delivered through the joint venture will continue to provide Statoil with an ocean transportation solution that is second to none”.

OSM Maritime Group will provide the lead technical management, supported by the MISC Group, during the construction of the vessels.

DOE to Invest $20 Million in New Oil and Gas Research Projects

14doe logoThe U.S. Department of Energy (DOE) announced the availability of $20 million for cost-shared oil and gas research projects to increase recovery efficiency from unconventional oil and gas wells and to prevent offshore spills and leaks. This new funding opportunity seeks projects that will advance DOE’s objective to support a more environmentally responsible, secure, and resilient U.S. energy infrastructure, while enhancing economic competitiveness and national security.

“This oil and gas research funding opportunity underscores the Department’s commitment to developing all of the nation’s energy resources,” said Acting Assistant Secretary for Fossil Energy Doug Hollett. “Increased efficiency and reliability of preventative and recovery measures promote our energy security, and contribute to making the United States energy dominant.”

Projects under this funding opportunity will support the Office of Fossil Energy’s efforts to ensure environmentally sustainable domestic and global supplies of oil and natural gas. Funded projects will cover three topic areas – two addressing unconventional oil and gas recovery and one focused on offshore oil and gas leak prevention.

Technology validation using field laboratories - $15 million

Advancement in subsurface diagnostics - $3 million

These two topic areas address critical gaps in the understanding of reservoir behavior and optimal completion, stimulation, and recovery strategies for unconventional oil and gas. The aim of these topic areas is to increase and enable more cost-efficient and environmentally sound recovery from shale gas, tight oil, and tight gas reservoirs.

Offshore spill and leak prevention - $2 million

This topic area focuses on offshore oil and gas spill and leak prevention. The aim of this topic is to develop innovative solutions that predict geologic hazards, and prepare for and prevent offshore incidents through risk reduction and mitigation technologies. Learn more about this funding opportunity HERE.

To learn more about the Department’s programs and research within the Office of Fossil Energy, visit their website HERE. For more about the Office of Fossil Energy’s National Energy Technology Laboratory (NETL) click HERE. Information on additional funding opportunities can be found HERE.

Cook Inlet Federal Lease Sale Yields more than $3 Million in High Bids

15CookInletCook Inlet Lease Sale 244 -- the first lease sale held in Alaska’s federal waters since 2008 -- today garnered $3,034,815 in high bids for 14 tracts covering roughly 76,615 acres in Cook Inlet, off Southcentral Alaska. All bids were submitted by Hilcorp Alaska LLC.

“Today was the first time in nearly a decade that parcels off Alaska have been leased. This is the latest sign of continued industry optimism in the Trump Administration,” said Vincent DeVito, Counselor to the Secretary for Energy Policy. This Administration understands that our lands offer vast energy development opportunities and that responsible energy development strengthens all aspects of our energy economy. Today's successful sale is another step in an America First energy strategy that puts us on our way toward energy dominance."

Cook Inlet Lease Sale 244 is the final to be held under the 2012-2017 Outer Continental Shelf (OCS) Oil and Gas Leasing Program (Five Year Program). It offered 1.09 million acres in Cook Inlet, comprising 224 blocks stretching roughly from Kalgin Island in the north to Augustine Island in the south.

“This sale represents an important step forward for energy development in Alaska,” said Dr. Walter Cruickshank, Bureau of Ocean Energy Management’s (BOEM’s) acting director. “It demonstrates our commitment to environmentally responsible energy development that provides economic opportunities and generates jobs. Expanded oil and gas production is critical to America’s economic and energy security, as we move to strengthen the Nation’s energy independence in accordance with the administration’s goals.”

Prior to today’s sale, twelve lease sales were held under the 2012-2017 Five Year Program, which offered about 73 million acres for development and generated about $3.275 billion in bid revenues.

The 2017-2022 Program is set to begin this summer and will be in effect until BOEM completes a new National OCS Oil and Gas Leasing Program as part of President Donald Trump’s America First Offshore Energy Strategy, as outlined in the President’s Executive Order 13795 on April 28, 2017, and amplified by Secretary Zinke’s Secretary’s Order 3350 on May 1, 2017.

The Cook Inlet Lease Sale terms 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.

Following today’s sale, each bid will go through a 90-day evaluation process to ensure the public receives fair market value before a lease is awarded. Lease awards will be posted to BOEM’s website as they are completed. BOEM will announce final sale statistics upon completion of evaluations. All materials and statistics for Lease Sale 244.

N-Sea Reaches One Million Man Hours LTI Free

Subsea IMR provider, N-Sea Offshore Limited, has reached one million man-hours without a lost time incident (LTI).

N-Sea sets a high example for outstanding SHEQ performance and the industry milestone, which was reached earlier this month, is reinforced by the recent launch of the N-Sea Golden Rules programme, which embeds excellence in SHEQ (Safety, Health, Environment, Quality).

16Roddy James Chief Operating Officer N SeaRoddy James, N-Sea Chief Operating Officer

N-Sea’s Chief Operating Officer, Roddy James, said: “At N-Sea we believe in an open and just culture and we are delighted to have reached this significant safety milestone.

“The hard work and dedication of the entire team has been integral to reaching this point. I would like to sincerely thank all my N-Sea colleagues, who have made a huge contribution to maintaining our exemplary attitude towards health and safety.

“Our Golden Rules initiative is a succinct illustration of N-Sea’s focus upon protecting our people from common hazards. Our ethos is always to operate in a safe, sound and swift manner; the Golden Rules set a benchmark for our approach to the work we undertake, on behalf of our global client base.”

The Golden Rules programme will help N-Sea continue to raise awareness of its commitment to SHEQ, both internally and externally with its partners around the world.

N-Sea is known for its innovative work as an independent offshore subsea contractor, specialising in IMR services for the oil and gas, renewable and telecom/utility industries, as well as for civil contracting communities. N-Sea provides near shore, offshore and survey services to major operators and service companies alike.

Eni Awarded 3 New Exploration & Production Blocks Offshore Mexico

Eni has been granted 3 of 10 offshore blocks awarded by Mexico’s National Hydrocarbon Commission (CNH) in the Sureste Basin, in the Gulf of Mexico. This result boosts Eni’s presence in a market that only opened up to foreign investments in 2014, in line with the country’s Energy Reform, and which has huge growth potential. The award is the outcome of the first bids called under “Ronda 2”, in which CNH offered blocks located in water depth ranging from 20 to 500 meters in the Sureste and Tampico-Misantla Basins.

1Eni messico CS firma 516Eni is the only international company to get 3 blocks out to the 10 assigned by Mexico’s CNH

Eni will be Operator of Block 10 (Eni 100%), Block 7 (Eni 45%, Cairn 30%, Citla 25%) and Block 14 (Eni 60%, Citla 40%), with all of the licenses to be managed through Eni Mexico. The contract awards, which will be production sharing agreements, are subject to final approval by the authorities.

Eni already holds a 100% stake in Area 1 in the Sureste Basin, where the exploration and appraisal campaign is successfully ongoing and a fast-track plan for the development of the Amoca field is being finalized, with plans for an early production phase. The new blocks are joined to Area 1 and, in the case of a successful exploration campaign, will allow Eni to build up a new core area of considerable size with significant operational synergies in the Country.

Eni has been present in Mexico since 2006, and it established its wholly-owned subsidiary Eni Mexico in 2015.

OSI Delivers Construction Phase of ATISA Network

2 1Atisa OSIOcean Specialists, Inc. (OSI) announces that it has completed its full scope of program work related to the ATISA submarine cable project. OSI has been engaged with DOCOMO PACIFIC since the earliest days of the project, helping shape the commercial and technical foundations of the program, with a continuing technical management role that extended through manufacturing, installation, and commissioning. The ATISA network was installed by NEC.

2 2OSI CableshipATISA brings much-needed capacity and redundancy to the region, with additional fiber optic connectivity to the islands of Saipan, Rota, and Tinian with high-capacity links to Guam. “DOCOMO PACIFIC and OSI have designed and delivered the ATISA network with service restoration and robust network capabilities fully in mind. OSI has appreciated the focus and drive with which the DOCOMO PACIFIC team has led the project; we are certain the network will bring significant benefit to the Marianas,” stated Tony Mosley, OSI’s Director of Asia Pacific.

“OSI’s team has worked side-by-side with us from Day One. Their suggestions and ability to balance the commercial, technical, and delivery aspects of the program were invaluable,” stated Jonathan Kriegel, President and Chief Executive Officer of DOCOMO PACIFIC.

OSI delivers network connectivity globally for telecom, energy, and scientific industries, with current projects spanning all regions of the world. Network development portfolio services range from market studies, partner identification, technology assessment, vendor selection and full network management of installation and commissioning. “As it relates to Asia Pacific, which is always a dynamic and important region, we are particularly proud of our capabilities; we have made a strong commitment to the region in terms of resourcing and staff, and it shows in our ability to meet the needs of this market,” said Tom Soja, Vice President of OSI.

Statoil: Green Light for Njord and Bauge

3 1StatoilNjordThe Njord A platform. (Photo: Thomas Sola/Statoil)

The plans for development and operation (PDO) of Njord and Bauge in the Norwegian Sea have now been approved by the authorities.

The Njord A platform and the Njord Bravo floating storage and offloading vessel (FSO) will be upgraded to recover the remaining resources in the Njord and Hyme fields, whereas Bauge is a new field development to be tied in to the Njord A platform.

“We are pleased that the authorities have now approved the plans for Njord and Bauge, two important fields on the Norwegian continental shelf. The investments, totaling NOK 20 billion, will trigger high activities and spin-offs for the Norwegian society and Norwegian supply industry,” says Torger Rød, Statoil’s head of project development in Statoil.

The remaining resources on the Njord and Hyme field total 175 million barrels of oil equivalent. This corresponds to the reserves produced from the Njord field since first oil in in 1997. In addition, 73 million barrels of oil equivalent will be produced from Bauge.

On behalf of the partnerships in the Njord, Hyme and Bauge licenses plans for the development and operation of the Njord and Bauge fields were submitted to Norwegian authorities on 27 March this year.

The original PDO for the Njord field was submitted more than 20 years ago. The field will now produce for another twenty years, and the partnership has decided to upgrade and reuse both the Njord A platform and the Njord Bravo FSO.

3 2Statoil njord bauge 1 1Bauge field illustration: Credit: Statoil

The Bauge field development concept includes one subsea template, two oil producers and one water inject.

“Kværner at Stord has been awarded the contract for upgrading the platform and work facilitating the tie-in of Bauge and potential future third-party tie-ins,” says Rød.

“Njord remaining on stream until 2040 is important for our specialist communities in Kristiansund and Stjørdal, as well as the mid-Norway supply industry. An upgraded field center and new infrastructure at Njord also allows for the development of other fields in the area,” says Siri Espedal Kindem, senior vice president, Operations North, Development and Production Norway.

Next year the Njord partners will award the contract for upgrading the Njord Bravo FSO. First oil is scheduled for the end of 2020.

Facts About Njord – Upgrading of Existing Platform

First oil in 1997 Njord was on stream from 1997-2016, and 54 wells were drilled
10 new production wells are planned on the field
In 2016 the Njord A platform and the Njord Bravo FSO were towed ashore, to Stord and Kristansund, respectively
Reserves: 175 million oil equivalent
Capital expenditures: NOK 15.7 billion
Partners: Statoil (operator) 20%, Engie E&P Norge AS 20%, DEA Norge AS 50%, Faroe Petroleum 7.5% and VNG Norge AS 2.5%.

Facts Bauge – New Field

The discovery is located some 16 kilometers north-east of the selected tie-in platform, Njord A
The development concept includes one subsea template, two oil producers, one water injector
Reserves: 73 million oil equivalent
Capital expenditures: NOK 4.1 billion

Partners: Statoil (operator) 35%, ENGIE E&P Norge AS 10%, Point Resources AS 17.5%, DEA Norge AS 27.5%, Faroe Petroleum Norge AS 7.5%, VNG Norge AS 2.5%

BP and Reliance Industries Bringing New Gas Production to India

4 1bp logo copy 34 2reliance industries logoReliance Industries Limited (RIL) and BP have announced that they are moving forward to develop already-discovered deepwater gas fields, bringing new gas production for India. The two companies have agreed to deepen and expand their partnership to work jointly across a wide range of areas throughout India’s energy sector.

‘R-Series’ deep water gas fields

RIL and BP announced that they will award contracts to progress development of the ‘R-Series’ deep water gas fields in Block KGD6 off the east coast of India. The R-series (D34) project is a dry gas development in water-depths of more than 2,000 meters, approximately 70 kilometers offshore. The R-series fields will be developed as a subsea tieback to the existing control and riser platform off Block KGD6. The project is expected to produce up to 12 million cubic meters (425 million cubic feet) of gas a day, coming on stream in 2020.

This is the first of three planned projects in Block KGD6 that are expected to be developed in an integrated manner, producing from about 3 trillion cubic feet of discovered gas resources. RIL and BP plan to submit development plans for the next two projects for Government approval before the end of 2017. Development of the three projects, with total investment of c. INR 40,000 crore (US$6 billion), is expected to bring a total c. 30-35 million cubic meters (1 billion cubic feet) of gas a day new domestic gas production onstream, phased over 2020-2022.

Mukesh Ambani, Chairman and Managing Director of RIL, said: “We are delighted to progress these developments, which will provide India with much needed indigenous energy and support the Prime Minister’s call for import substitution and the development of a gas-based economy. The solid relationship between our two companies is a great example of what can be achieved while working together at scale.”

Speaking in New Delhi today, Bob Dudley, BP Group Chief Executive, welcomed the investment: “This is an important step forward for BP in India. Working closely together, Reliance and BP are now able to develop these major deep water gas resources offshore India efficiently and economically. It is testament to our commitment to working in partnership with Reliance and with the Government to produce more energy in India, for India”.

India today consumes over 5 billion cubic feet a day of natural gas and aspires to double gas consumption by 2022. Gas production from the 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.

Execution of the R-Series and following projects will require deployment of advanced skills, processes and technologies through the combined partnership of RIL and BP to develop and produce gas from these ultra-deep reservoirs.

The implementation of other two projects in Block KGD6 is subject to applicable regulatory and Government approvals.

Expanding partnership

RIL and BP will expand their existing partnership for strategic cooperation on new opportunities across India’s energy sector. Under the agreement the two companies will jointly explore options to develop differentiated fuels, mobility and advanced low carbon energy businesses in India, as India transitions to a low-carbon world.

The companies expect to collaborate, in addition to the conventional transportation and aviation fuels retailing, on unconventional mobility solutions, addressing electrification, digitization and disruptive mobility trends. Together, these collaborations will seek to address the mobility needs of urban, rural/farm, industrial/commercial, and highway consumers in India, applying the leading capabilities of both partners.

Mukesh Ambani commented: “This strategic partnership not only strengthens the relationship between two global energy leaders, but is also in line with and supports the forward-looking policies and vision of the Government of India.”

Bob Dudley added: “India’s demand for both energy and mobility is growing and evolving rapidly. This presents many opportunities for BP and Reliance to build on our existing strong relationship in upstream and expand our partnership further downstream. Combining skills and experience from both our companies, we expect to cooperate on mobility and advanced low carbon solutions and jointly explore other opportunities throughout India’s energy sector.

India is a rapidly growing market with a population of 1.3 billion people, consuming around 4 million barrels a day of oil products and with demand for fuels expected to grow by 5-7% per year over the next decade. BP and RIL are committed to being one of India’s preferred energy partners now and in the future.

Cairn Energy Secures New Licenses in Mexico Bid Round

5CairnlogoCairn announces it has secured interests in two licenses in the Mexico offshore bid round.

The licenses (one operated and one non-operated, covering ~1,100km2) are located in the Gulf of Mexico in the shallow water Sureste basin in water depths of 100-500 meters and ~50km offshore:

  • Block 7: ENI (45% operator), Cairn (30%), Citla (25%)
  • Block 9: Cairn (65% operator), Citla (35%)

Multiple-attractive prospects in a variety of play types have been identified within this highly prolific, proven hydrocarbon province which has recently opened to international oil companies. The Mexican Gulf region is significantly under-explored compared to the nearby analogous United States Gulf of Mexico.

The licenses were secured by Capricorn Energy Limited a wholly owned subsidiary of Cairn Energy PLC with the Production Sharing Contracts scheduled to be signed later this year with the Government of Mexico. The contract awards are subject to the final approval of the authorities. Cairn anticipates exploration drilling to commence in the 2019-2020 period on both blocks.

Cairn Energy CEO, Simon Thomson, said:

"We are delighted with these awards which we believe provide an exciting opportunity to build a strategic portfolio over time in this highly prolific yet under-explored region.

As we build on the success of discoveries in Senegal it is important to access new acreage to provide exploration drilling opportunities in the future.

Cairn and its partners have identified and secured our favored blocks with multiple stand-alone prospects and numerous follow-on tie-back opportunities based on 3D seismic data.

We are partnered with ENI, an experienced explorer and operator in Mexico, as well as Citla Energy, a Mexican focused, exploration company and look forward to working with our new partners and the Government of Mexico to deliver the work program in the coming years."

ExxonMobil Makes Final Investment Decision to Proceed with Liza Oil Development in Guyana

6Guyana june 2017 updated project map articleExxon Mobil Corporation (NYSE:XOM) says it has made a final investment decision to proceed with the first phase of development for the Liza field, one of the largest oil discoveries of the past decade, located offshore Guyana.

The company also announced positive results from the Liza-4 well, which encountered more than 197 feet (60 meters) of high-quality, oil-bearing sandstone reservoirs, which will underpin a potential Liza Phase 2 development. Gross recoverable resources for the Stabroek block are now estimated at 2 billion to 2.5 billion oil-equivalent barrels, which includes Liza and other successful exploration wells on Liza Deep, Payara and Snoek.

The Liza Phase 1 development includes a subsea production system and a floating production, storage and offloading (FPSO) vessel designed to produce up to 120,000 barrels of oil per day. Production is expected to begin by 2020, less than five years after discovery of the field. Phase 1 is expected to cost just over $4.4 billion, which includes a lease capitalization cost of approximately $1.2 billion for the FPSO facility, and will develop approximately 450 million barrels of oil.

“We’re excited about the tremendous potential of the Liza field and accelerating first production through a phased development in this lower cost environment,” said Liam Mallon, president, ExxonMobil Development Company. “We will work closely with the government, our co-venturers and the Guyanese people in developing this world-class resource that will have long-term and meaningful benefits for the country and its citizens.”

The Liza Phase 1 development can provide significant benefits to Guyana, including jobs during installation and operations, workforce training, local supplier development and government revenues to fund infrastructure, social programs and services.

The development received regulatory approval from the government of Guyana.

The Liza field is approximately 190 kilometers offshore in water depths of 1,500 to 1,900 meters. Four drill centers are envisioned with a total of 17 wells, including eight production wells, six water injection wells and three gas injection wells.

The Liza field is part of the Stabroek Block, which measures 6.6 million acres, or 26,800 square kilometers. Esso Exploration and Production Guyana Limited is operator and holds a 45 percent interest in the block.

Hess Guyana Exploration Ltd. holds a 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent.

Esso Exploration and Production Guyana Limited is continuing exploration activities and operates three blocks offshore Guyana – Stabroek, Canje and Kaieteur. Drilling of the Payara-2 well on the Stabroek block is expected to commence in late June and will also test a deeper prospect underlying the Payara oil discovery.

Expro Secures $10million Well Services Contract Extension from Apache North Sea

7Expro Apache UK Forties Alpha 02Expro has secured a $10million well services contract extension with Apache North Sea.

The contract covers a range of well services including slickline, cased hole services and pumping services, as well as support in delivering coiled tubing services. This utilizes a multi-skilled crew covering the UK North Sea Forties platforms, ensuring a consistently high approach to safety and service quality.

Expro has worked with Apache since 2004 and after securing the initial well services contract in 2009, has now been awarded two further one-year extensions (to 2019).

Commenting on the major award, UK Area Manager, Gary Sims, said:

“As one of the world’s largest well intervention companies, we remain committed to maintaining our strong working relationship with Apache.

“Our 40 years of experience mean that we are ideally placed to support this comprehensive range of intervention related services, providing a safe and cost-effective approach to maximize incremental production from mature assets.

“Expro can also provide additional cased hole services on demand, avoiding costly downtime, ensuring our customers receive the fast response times they need in an increasingly cost sensitive market place.”

Claxton Awarded Casing Cutting and Recovery Combined Services Contract with Southern North Sea Operator

8Claxton DecommissioningClaxton, a leading supplier of engineering and services for shallow-water, jackup-depth markets in subsea services company Acteon, has been awarded a contract to riglessly casing cut and recover a total of seven wells in the Southern North Sea across two of the operator’s, normally unmanned, platforms, along with an additional subsea suspended well at one of the locations.

Work is scheduled to commence in July at the first location, located around 180km off the Yorkshire coast, with work on the second platform, in the Dowsing Fault Zone of the Sothern North Sea, commencing shortly afterwards; the combined project completion is estimated at just under 100 days.

The first NUI scope of work includes the removal of Christmas trees in preparation for the removal of the production tubing, wellhead preparation in readiness to also undertake the sub-mudline multi conductor/ casing cutting and recovery, and severance and conductor recovery of the suspended subsea well. Due to limited deck space, work will be conducted as a combined operation using a jack up lift barge ‘JULB’ and without the use of a drilling rig.

Laura Claxton, Managing Director, Claxton, said: “Our global experience allows us to provide the most comprehensive decommissioning package for all of our clients, but always having an eye on providing the most cost-effective solution for abrasive severance, cut verification and recovery.

“We will be using a 150te hydraulic proving jack package, Claxton Double Drilling Units (DDUs) for drilling and pinning and rapid cut bandsaws for cutting the combined multi strings. Marine growth stripping and removal using our purpose designed tooling will also be delivered, along with multi-string severance using our proprietary abrasive water jet cutting system SABRETM.”

The scope of work on the second platform includes Christmas tree and tubing removal, supply of blowout preventer (BoP) equipment, and the use of coiled tubing for cement squeezing operations. Tubing and conductor severance and recovery will be performed using Claxton’s own SABRETM abrasive cutting system - 10ft below seabed. The limited deck space on the platform deck also means that Claxton has developed a bespoke, all-purpose work deck.

Laura Claxton continued: “As part of the provided solution our equipment is unique and can again offer the operator real savings. Our bottom hole anchor and catch tool system for example, allows recovery of the conductor stump and conductor during the surface recovery stage reducing this to a single operation and removing the need for fishing tools. “We have also provided an engineered and aligned solution to reduce the number of slewing operations required by the JULB crane with a revision to our existing tubing laydown frame by incorporating a traveling bogie system. The frame and bogie eliminates the need for the crane to slew from the well centre while still allowing tubing to be laid out on deck. This saves valuable time on a project.”

Well abandonment is just one of the many services Claxton can offer to reduce the cost of your decommissioning project. Learn more about Claxton’s decommissioning services.

Aquaterra Energy Wins Multi-Million Pound North Sea Abandonment Contract

Aquaterra Energy, a leading global offshore engineering solutions provider, has won a major contract to supply subsea high pressure riser (HPR) equipment and services for a subsea abandonment project in the central North Sea.

The multi-million pound deal will see Aquaterra facilitate the abandonment of ten subsea wells via deployment of a subsea HPR system from a jack-up rig. The scope of work could be extended to include two further subsea wells bringing the total number of abandonments to 12.

Riser analysis was completed in-house by Aquaterra and validated by Bureau Veritas. It has confirmed a 50-year return storm operating envelope after HPR and rig optimisations were implemented. This has simplified the project operationally and reduced costs to the operator overall.

Aquaterra’s Initiation Engineering or ‘Well Start’ specialism has been implemented on the project to deliver a one-stop shop for extensive expertise to optimise well activity by taking responsibility for the entire first phase of the well. This approach minimises third party interfaces across a client’s project and addresses supply and equipment requirements, before the introduction of a blowout preventer. It can also mitigate risk and cut down on costly logistics, capex/opex, the number of crew involved and therefore, helicopter and accommodation needs.

9Aquaterra image 1George Morrison is managing director of Aquaterra Energy and creator of the Well Start specialism

George Morrison, managing director of Aquaterra Energy, said: “Aquaterra has built a successful track record of jack-up and subsea high pressure riser operations over recent years using similar systems. The use of jack-ups can potentially mitigate the heavy loading implications and weather constraints often associated with semi-submersibles in shallow water and thus, extend the operating envelope and productive time through a reduction in waiting on weather.”

With global rates for semi-submersibles averaging around USD 250,000 per day in 2016, day rate rental charges for jack-ups in Europe and Asia remain considerably cheaper.

Morrison added: “A change in the default mindset is needed to consider jack-up drilling units equipped with a HPR for shallow water subsea drilling, completion, intervention and abandonment activities as they can significantly reduce risk and lower operational costs when compared to a semi-submersible completing the same operation.

“Our project history and ‘Well Start’ service has shown that we are more than just an equipment provider but are a trusted turnkey solutions company. We can manage the risk and interfaces associated with jack-up subsea conversion packages to ensure it is safely and efficiently carried out. The cost savings, technical benefits and greater operational up time that this translates to, particularly during these challenging times, is key.”

The project is expected to be completed by Q4 2017.

Industry Project on Standardizing Subsea Processing Boosts up to Phase 2

10DNV CLOSEUP LAPTOPSubsea processing offers great potential for the oil and gas sector, but is also a relatively young field of technology, causing costly and inefficient tailor-made solutions. The DNV GL-led joint industry project (JIP) on standardizing subsea processing aims to reduce cost in a lifetime perspective. Initially focusing on subsea pumping, the partners in Phase 1 have now concluded the functional description of subsea pumping, while Phase 2 will deliver standardized guidelines. With all the four leading system suppliers on board, new operators are still welcome to join the project.

According to DNV GL’s seventh annual benchmark study, Short-term agility, long-term resilience, subsea technology is the highest-ranked area globally for conducting R&D among emerging technologies in 2017. In addition, standardization efforts are on the rise to remove complexities, with two-thirds of respondents saying their organization will seek greater standardization of tools and processes in 2017.

Although subsea processing is a target area for innovation, operational experience has also grown in recent years, with significant developments made by, among others, Total, Petrobras, Shell and Statoil. However, the lack of standardization which is driving costs up is still seen to make subsea processing less competitive than alternative solutions.

Kristin Nergaard Berg, JIP project manager, DNV GL – Oil & Gas, says: “Subsea standardization offers tremendous benefits. It allows flexibility for tailor-made facilities at a system level through standard functional descriptions and specifications, while also increasing predictability in the value chain. This will not only lower transaction costs and accelerate implementation for all parties, but also allow freedom to innovate and employ new technology.”

The kick-off for Phase 2 of the Subsea Processing JIP was recently held at DNV GL’s headquarters at Høvik, Norway. The JIP includes system suppliers Aker Solutions, GE Oil & Gas, OneSubsea and TechnipFMC and operators Shell, Statoil and Woodside. Phase 2 is expected to lead to a guideline and eventually a recommended practice for subsea pumping systems.

Building on the concluded functional description from Phase 1, the JIP will continue by developing system level requirements and design classes, as well as harmonized work processes and design standards.

Phase 2 activities are related to:

  • Standards, functional requirements and specifications
  • System design
  • Pump modules and pressure-containing equipment
  • Control system and instrumentation
  • Power system
  • Materials and welding
  • Qualification work processes and test requirements.

Hans Christian Nilsen, Head of Boosting Technology, Aker Solutions, says: “The subsea industry is looking towards standardization for ensuring cost-efficient and reliable technology. Aker Solutions welcomes a harmonized approach with the vendors and oil companies, which will enable the future large-scale use of subsea boosting.”

Morgan Harland, General Manager, Subsea & Pipelines, Woodside, says: “Through innovation and collaboration, Woodside aims to deliver outstanding performance of our subsea and pipeline systems throughout the entire lifecycle. The standardization of subsea processing JIP and its initial focus on subsea pumping hits the mark with standardized guidelines being developed for subsea processing modules and interfaces that are efficient, reliable and readily installed and serviced. We use subsea boosting in our subsea production systems and know that these are important lifecycle cost drivers.”

Kjell Eriksson, Regional Manager Norway, DNV GL – Oil & Gas, says: “Like more conventional solutions, subsea processing must prove to be cost efficient to be considered attractive. At the same time, subsea processing will be an enabler for increased oil recovery. Through collaboration with the big players in the subsea industry, this JIP drives subsea processing towards being a competitive and viable solution for a wide range of future oil and gas fields.”

Phase 2 will be completed in 18 months.

Integrated Approach Accelerates Understanding of Petroleum Systems

11 2CGGlogoCGG’s JumpStart™ multi-client geoscience programs integrate the most advanced seismic data with reviewed, calibrated and interpreted well and geological data for petroleum systems evaluation, supported by regional interpretations and reports. The aim is to provide a single source for all the available information about an area in a consistent, accessible and ready-to-use format, in order to maximize the value of the seismic data and provide a regional context to support exploration efforts. There are seven JumpStart programs nearing completion, offshore Mexico, Brazil, Gabon, Australia, Indonesia & Timor Leste, and Norway, with more programs in the pipeline.

11 1 2CGG NorthViking LargeMiocene-Pliocene channel complex from the Northern Viking Graben JumpStart program (image courtesy of CGG Multi-Client & New Ventures).

The three major components of a JumpStart program are: the acquisition and processing, or reprocessing, of seismic data; collation and analysis of available wells, including core data where possible; and integration of this upgraded data, and other available information, into a comprehensive interpretation and evaluation of the basin’s petroleum system(s). The typical workflow starts with a regional geology review which forms the basis for the interpretation of the seismic data, basin model building, and play fairway analysis.

Well data represent true samples of the Earth and, as such, are essential to calibrate geological models. However, the number of wells available for review in JumpStart programs varies greatly, depending on the maturity of the basin and the data-release policies in the area; in the North Viking Graben, for example, 140 selected wells are being analyzed, whereas the Mexican Encontrado program uses 16. Therefore, a consistent petrophysical and stratigraphic review of the well data is undertaken to provide a robust chronostratigraphic framework for well ties. Where data is available, biostratigraphy is used to help define Consistent Stratigraphic Markers across the basin.

Previous well interpretations have frequently been found to be inconsistent, largely due to the scientific knowledge and tools available at the time the well was drilled. In the North Viking Graben, some older sands were wrongly assigned to be the Agat Formation, but closer examination of the age and composition enabled them to be reassigned and a better stratigraphic correlation was achieved between wells and seismic. Similarly, re-examination of the previous interpretation of wells in Mexico’s Encontrado program has significantly changed the understanding of the basin. Additional wells from the US Perdido area are now being analyzed to verify this. In Gabon, the re-interpretation of well data acquired through the pre-Aptian salt has revealed potential for an additional late syn-rift sand play to exist in the ultra-deep offshore area, different from the one commonly known as the Gamba sandstone.

Typically, the new stratigraphic markers and fast-track seismic data are used from an early stage to generate seismic-to-well ties to calibrate velocity models and formation markers, and are used for quality control throughout the seismic processing. The well data can also be used to generate pre-stack attributes and AVO gather synthetics which are used to control the quality of AVO signature preservation throughout the seismic processing flow.

Within this framework, additional data such as potential fields, geochemistry and satellite mapping of offshore hydrocarbon seeps are integrated into the imaging and interpretation of the seismic and the petroleum system evaluation. On completion of seismic processing, full structural and stratigraphic interpretation of the new data is performed for key horizons, and seismic attributes (pre- and post-stack) are extracted to map the potential presence of fluids and facies. Stratal Slicing on depositional horizons and spectral decomposition are used to provide a clearer understanding of lateral seismic facies and reservoir quality variations.

JumpStart data sets, comprising compiled, reviewed, and ready-for-use data with a full suite of interpreted information, comprehensive reports, prospectivity evaluation, and risk assessments, are available. Visit CGG on booth #630 to find out more about how JumpStart programs can help accelerate your petroleum systems understanding, saving you valuable time and enabling you to assess new areas more quickly.

Mermaid Awarded Subsea Contracts from Oil Majors

Mermaid Maritime Public Company Limited (“Mermaid”) announces that its South East Asian business units have recently been awarded subsea contracts from oil majors with a combined total estimated potential contract value of USD 4.3 million.

The first highlighted package of work involves the DP2 Dive Support Vessel ‘Mermaid Sapphire’ with a Work Class ROV and cement/grouting spread carrying-out a 16-day lump sum project involving subsea pipeline freespan rectification for a national upstream oil and gas company in the Gulf of Thailand.

12MermaidSapphireMermaid Sapphire: Photo credit: Mermaid Maritime

The second highlighted package of work involves a 2-year contract carrying out site survey & navigation services offshore East Kalimantan, Indonesia, for an international upstream oil and gas company using the client’s or third party chartered-in vessel.

Mermaid’s contract win announcements as published from time to time on SGXNet are not exhaustive as Mermaid continues to be awarded other smaller contracts from time to time in the ordinary course of business which are added to its order book.

Financial Effects

Assuming that the contracts had commenced and had been completed within the most recent financial year (the Company’s last financial year ended 31 December 2016), the contracts would have had a non-material effect on the earnings per share of the Company (on a consolidated basis) and a non-material effect on the net tangible assets per share of the Company (on a consolidated basis) for that financial year.

Interest of Directors and Controlling Shareholders

None of the directors or controlling shareholders of the Company has any interest, direct, or indirect, in the contracts. There are also no new directors proposed to be appointed to the Company in connection with the contracts.