Deloitte’s survey of oil and gas operators and oilfield services companies* has found that a lack of effective supply chain collaboration means companies are missing out on maximizing the potential value from the UK Continental Shelf (UKCS).

74% of respondents said collaboration was an integral part of their day-to-day business but only 27% reported that the majority of their efforts resulted in a successful outcome. Cost reduction was found to be the main driver for collaboration today, with nearly a third (31%) of company respondents in agreement. 90% said that supply chain collaboration would also play a greater role in their company’s success.

Nick Clark, a director in Deloitte’s consulting team and contributor to the research, said: “While it’s encouraging that collaboration is seen by the industry as an important tool in helping companies succeed in maximizing economic recovery of the UKCS in line with the Wood Report, there’s clearly work to be done, and fast given the current tough environment.

“The industry needs to address a number of practical, cultural and behavioral barriers that are standing in the way of realizing this successful future. These include fundamentals such as a lack of effective financial incentives, a lack of clear communication and misalignment of expectations between operators and service companies in execution.”

The most critical finding highlighted the discrepancy between what drives successful collaboration, and the actions of leadership and business processes to underpin it. Whilst there was clear recognition of the value of collaboration and what’s needed to make it happen, trust and mutual benefits for example, less than 10% said that leadership regularly emphasized its importance or included it in their business strategy.

Despite this 20% of respondents still said they actively sought out opportunities to collaborate, which shows that the potential is there if the right leadership and incentives are in place.

Deloitte suggests that whilst industry must take the lead to make collaboration effective in the UKCS, it should look to the regulator, the Oil and Gas Authority (OGA), and Oil and Gas UK (OGUK), the industry trade body for support, pointing out that initiatives like OGUK’s Efficiency Task Force can be a real driver for positive change.

Oil & Gas UK’s business development director, Stephen Marcos Jones, commented: “In a world of a fallen oil price and high costs, industry is facing a difficult time. Whilst there are some signs of recovery - through an upturn in production and concerted focus on improving efficiency - there's also growing consensus that much more needs to be done. Deloitte’s report is a welcome contribution to this important debate, it is valuable to have a means to measure industry’s progress in terms of collaboration – which is no easy task.

“Collaboration is crucial if we're to fulfil Sir Ian Wood's vision to maximize economic recovery from the UK Continental Shelf.

“I believe industry is now starting to readjust its way of working together. It is vital we work together proactively - not just between operators, but crucially between operating companies and the wider supply chain - to deliver the transformational change we need to see.

“That is why Oil & Gas UK has put in place an Efficiency Task Force - championed by leaders from across the industry - we hope this group will challenge existing behaviors and be a catalyst for pan-industry improvement, in addition to the extensive work being undertaken by companies individually.”

Clark continues; “Thirty years ago health and safety was the major focus for the North Sea, and the industry made that a central tenet of its culture – for collaboration to succeed it has to be addressed with the same urgency and senior leadership.

“Our research shows that the industry recognizes this, and the critical value that effective supply chain collaboration can deliver in securing the future of the UKCS. We need to act fast and I believe that every company involved in the North Sea will want to play its part in making it a safe, collaborative, efficient and profitable region for many years to come.”

About the Deloitte oil and gas collaboration survey

This is the first Deloitte oil and gas collaboration survey in the UK and took place between 1st July and 31st July 2015.

The survey was supported by industry body Oil and Gas UK.

*61 people participated from a wide range of operators and oilfield services companies

For more information please visit: www.deloitte.co.uk/UKCS-collaboration or www.deloitte.co.uk/UKCScollaboration

On 2 October 2015, Statoil acquired First Oil’s 24% equity share in the UK license for the Alfa Sentral field for USD 15 million.

Alfa Sentral is a c.60 mmboe gas and condensate field planned to be developed as a tie-back to the existing infrastructure for Sleipner on the Norwegian Continental Shelf (NCS), which Statoil operates. Alfa Sentral will therefore increase the utilization of the Sleipner facilities.

“Statoil has set ambitious goals for future activity, production and value creation. This transaction demonstrates the potential on both the UK and Norwegian side of the Continental Shelf. The acquisition of this Alfa Sentral license increases the resource base and strengthens our efforts to further develop the Sleipner area towards 2030", says Mette Halvorsen Ottøy, senior vice president for the operations south cluster in Development & Production Norway (DPN).

Through this transaction Statoil has taken a 24% interest in UK Continental Shelf (UKCS) license P312 which, with license PL046 on the NCS, comprises the Alfa Sentral field. Statoil is the operator in PL046 with a 62% holding.

As a result, Statoil has increased its equity holding in a high priority project in a core area, deepening its presence on both the NCS and UKCS. The transaction is expected to close by the end of 2015.

Concept selection for the Alfa Sentral project was passed in September 2015. Negotiations to unities the field will commence shortly. A final investment decision is planned for late 2016 with production start-up in 2020.

Aker Solutions has been awarded a contract from Murphy Sabah Oil Co., Ltd. (Murphy) to deliver the subsea production system for the Rotan deepwater natural gas development offshore Malaysia.

The delivery includes hardware for four subsea wells, a hub manifold, in-line tees, a connection system and production control system. First deliveries are scheduled for the second quarter of 2016. The contract will be booked as part of the company's third-quarter order intake.

"We're very pleased to team up with Murphy on this important development," said Ravi Kashyap, country manager for Aker Solutions in Malaysia. "We look forward to continuing the good cooperation we've built over several years having worked with Murphy on other projects in this strategically important region."

Aker Solutions has worked with Murphy on the Kikeh oil and gas project, the first deepwater development in Malaysia, and the Siakap North-Petai oil and gas development, a tieback to Kikeh. Both fields are in Block K offshore East Malaysia at the easternmost state, on the island of Borneo.

Statoil and its partners last week put the first subsea gas compression facility on line at Åsgard in the Norwegian Sea. Subsea compression will add some 306 million barrels of oil equivalent to total output over the field’s life.

This subsea technology milestone opens new opportunities in deeper waters, and in areas far from shore.

“This is one of the most demanding technology projects aimed at improving oil recovery. We are very proud today that we together with our partners and suppliers have realized this project that we started ten years ago,” says Margareth Øvrum, Statoil’s executive vice president for Technology, Drilling and Projects.

Recovery from the Midgard reservoir on Åsgard will increase from 67 percent to 87 percent, and from 59 percent to 84 percent from the Mikkel reservoir. Overall, 306 million barrels of oil equivalent will be added.

“Thanks to the new compressor solution we will achieve increased recovery rates both at Midgard and Mikkel, extending the reservoirs’ productive lives until 2032,” says Siri Espedal Kindem, senior vice president for Åsgard operations.

Demanding technology development

As a field gets older, the natural pressure in the reservoir drops. In order to recover more oil and gas, and get this to the platform, compression is required. The closer to the well compression takes place, the more oil and gas can be recovered.

Traditionally compression plants are installed on platforms or onshore, but this plant is located in 300 meters of water.

Due to the challenging location, quality in all parts of the project has been essential, and will help ensure high regularity, maximum recovery and robust production.

The project started in 2005, and the plan for development and operation (PDO) was approved in 2012.

An estimated eleven million man-hours have been spent from the start until completion. More than 40 new technologies have been developed and employed after prior testing and verification. Some of this work has taken place at Statoil’s Kårstø laboratory in Western Norway.

Overall, project cost were just above NOK 19 billion. Many small and big suppliers have helped to develop the sophisticated underwater compressor system.

Establishing the necessary support functions onshore has been an important and substantial part of the project. A spare compression train will be stored in custom designed halls at the onshore supply base Vestbase in Kristiansund.

“High-quality, regular maintenance of the subsea modules will also be performed here, helping ensure operational excellence for Åsgard,” says Espedal Kindem.

Technology for the future, and new potentials

The Midgard and Mikkel gas reservoirs have been developed using subsea installations. The two gas compressors now installed on the seabed are located close to the wellheads.

Moving the gas compression from the platform to the wellhead substantially increases the recovery rate and life of the fields. Prior to gas compression, gas and liquids are separated out, and after pressure boosting recombined and sent through a pipeline some 40 kilometers to Åsgard B.

In addition to improving recovery subsea gas compression will be more energy efficient than the traditional topside solution. The technology reduces significantly energy consumption and CO2 emissions over the field’s life.

Today almost 50 percent of Statoil’s production is recovered through some 500 subsea wells. Statoil’s subsea expertise is essential to successful production efficiency improvement and increased oil recovery efforts.

“Subsea gas compression is the technology for the future, taking us a big step closer to our ambition of realizing a subsea processing plant, referred to as the subsea factory”, says Øvrum.

Such a plant will facilitate remotely controlled hydrocarbon transportation. Current topside operations will thus be moved to the seabed, allowing oil and gas to be recovered that would not otherwise be profitable. This is an important element of increased recovery on the Norwegian continental shelf.

Aqueos Corporation, a premier subsea service provider for the offshore oil and gas sectors of the Gulf of Mexico and the Pacific West Coast, receives a prestigious safety award from a major Offshore Oil & Gas operator.

This distinguished award was presented to Aqueos President and CEO, Ted Roche, during a recent Safety forum and recognizes Aqueos Corporation for “Safety Excellence” for working over 505,592 hours without a recordable injury. “This is evidence of the hard work and commitment of our offshore personnel, a supportive and talented project management and administrative staff, and steadfast senior management all working as a focused team,” comments Ted Roche.

Roche further commented, “We attribute a large part of our success to continuous improvement, communication, and remaining focused on our core value of safety. Even in these difficult market conditions, the team at Aqueos looks forward to continued managed growth without sacrificing our core values.”

Aqueos Corporation, with offices in Broussard, LA and Ventura, CA, provides marine construction and specialty subsea services, including a complete range of commercial diving, remotely operated vehicles (ROV’s) and vessel-related services primarily to the offshore oil and gas markets.

Registration totals exceeded expectations as 13,500 global exploration and production professionals gathered at the Society of Petroleum Engineers (SPE) flagship event the Annual Technical Conference and Exhibition (ATCE) at the George R. Brown Convention Center in Houston over three days last week 28-30 September.

“2040: The Journey and the Destination—Diverse Perspectives” was the Opening General Session theme on Monday. ATCE 2015 General Chairperson, Gustavo Hernández-García, director of operations for PEMEX E&P, introduced a distinguished panel of industry experts who discussed current trends and the recent challenges faced by the oil and gas industry. However, discussion stressed the resilience of the industry, the continued importance of fossil fuel energy to the world economy, and reassurance the industry will come through a difficult period and be stronger. Panel member Scott Tinker, director of the Bureau of Economic Geology said the energy mix has changed little in the past 35 years. “It’s driven by security. Is energy affordable, available, reliable, and sustainable? A lower price over a long time extends the future of oil.” He adds, “I continue to believe that energy is the greatest industry on the planet. It underpins everything.”

2015 President Helge Hove Haldorsen focused his comments on “the new normal.” At the Opening General Session he said, “We need to continuously adapt, strengthen, and reinvent our industry because oil and gas will be needed for decades to come.” On Wednesday he wrapped up his presidential term saying, “We will see what the new normal will be.”

Nathan Meehan began his term as SPE 2016 president with his vision stating, “We are on a mission to educate and provide safe, affordable energy to improve people’s lives.” Meehan said his priorities for the year ahead will focus on stressing public benefit; mentoring the next generation; sustainability; as well as health, safety, and environmental issues.

The more than 400 technical presentations provided break-through and improved efficiencies for best practices for the oil and gas industry. The 500 exhibits offered promising new and enhanced products and services. Networking opportunities were expanded due to the Open Access Day on Wednesday where more than 400 people took advantage of the complimentary registration. The conference featured more than 45 technical sessions, 34 training sessions, and young professional and student events and activities.

Some new features of the conference included the ENGenious program, which resulted in standing room only presentations from innovative technology companies. Another new feature was the opportunity to access live-stream and virtual sessions for those who could not attend the conference.

Participating in ATCE were engineers, operators, scientists, managers, and executives involved in all aspects of the global petroleum industry. ATCE offered unique opportunities for people at all career levels - including young professionals and students - to meet industry experts, network with peers, and access new technologies.

ATCE 2016 will be held in Dubai 26-28 September at the Dubai World Trade Centre.

Shell has provided an update on the Burger J exploration well, located in Alaska’s Chukchi Sea. The Burger J well is approximately 150 miles from Barrow, Alaska, in about 150 feet of water. Shell safely drilled the well to a total depth of 6800 feet this summer in a basin that demonstrates many of the key attributes of a major petroleum basin. For an area equivalent to half the size of the Gulf of Mexico, this basin remains substantially under-explored.

Get background colour from dictionary with a fallback to default value. Shell has found indications of oil and gas in the Burger J well, but these are not sufficient to warrant further exploration in the Burger prospect. The well will be sealed and abandoned in accordance with U.S. regulations.

"The Shell Alaska team has operated safely and exceptionally well in every aspect of this year's exploration program," said Marvin Odum, Director, Shell Upstream Americas. "Shell continues to see important exploration potential in the basin, and the area is likely to ultimately be of strategic importance to Alaska and the US. However, this is a clearly disappointing exploration outcome for this part of the basin.”

Shell will now cease further exploration activity in offshore Alaska for the foreseeable future. This decision reflects both the Burger J well result, the high costs associated with the project, and the challenging and unpredictable federal regulatory environment in offshore Alaska.

The company expects to take financial charges as a result of this announcement. The balance sheet carrying value of Shell's Alaska position is approximately $3.0 billion, with approximately a further $1.1 billion of future contractual commitments. An update will be provided with the third quarter 2015 results.

Shell holds a 100% working interest in 275 Outer Continental Shelf blocks in the Chukchi Sea.

Operations will continue to safely de-mobilize people and equipment from the Chukchi Sea.

Claxton, an Acteon company, has successfully installed a high-pressure drilling riser system as part of a multimillion-pound contract for the Catcher area field development in the Central North Sea.

Owen Lewis, project engineer, Claxton, said, “Claxton was the only company to offer Premier Oil a fully-forged riser design option in the early tender stages of the project, and they recognized the value of it. Each joint was forged from a single billet of material with no joining welds, which makes the riser stronger than traditional systems. The riser’s fatigue life far exceeds the duration of the drilling phase of this project. We also provided optimum deployment times for the riser package, through the use of hydraulic handling tools and bolt tensioning equipment.”

The system was installed for Premier Oil’s Catcher area field development, which includes the development of the Catcher, Varadero and Burgman fields in Block 28/09a in the UK’s central North Sea.

Claxton’s scope of work includes providing the subsea connector to latch the riser with the subsea wellhead; riser tensioning interface from the riser to the rig’s tension system; all riser handling tools and a suite of custom-designed bolt tensioners, which will facilitate flange make-up. Acteon sister company, 2H Offshore, provided the riser analysis for the Catcher development.

Claxton secured the contract last year and began mobilization in late July 2015. The contract is for three-and-a-half years, with a possible extension.

“This project has been an exciting challenge throughout, with the design undertaken in-house to integrate a fully-forged system with a new flange design,” said Lewis. “One challenge was incorporating the tubing hanger alignment mechanism within our stress joint assembly. Claxton succeeded in delivering a unique guide frame design attached to the stress joint, which provided consistent and repeatable positioning of the tubing hanger in the wellhead. The riser has been installed successfully, with the first well nearing completion.”

The oil and gas industry is by nature one of the most challenging environments in the world, so a high level of business integrity is critical to safely keep operations up and running. As a result of its commitment to continuous improvement in the industry, Trelleborg’s offshore operation in England has been awarded an International Organization for Standardization (ISO) / Technical Specification (TS) 29001:2011 certification.

The standard defines the quality management system requirements for the design, development, production, installation and service of products for the petroleum, petrochemical and natural gas industries.

Ray Cann, Operations Director for Trelleborg’s offshore operation, says: Meeting the criteria involved creating and implementing detailed procedures and auditing, as well as facilitating various cross functional meetings with individual departments over eight months. In addition we had to complete three British Standards Institute audits - a pre-assessment and stage one and two audits.

Though it was challenging in parts, we were committed to ensuring that all tasks were completed as thoroughly and effectively as possible and the hard work paid off. We believe that this accreditation will provide our customers with added peace of mind and the assurance of consistently high quality products and services.”

Developed as a result of a partnership between ISO and the international oil and gas industry (led by the American Petroleum Institute - API), ISO 29001 specifically focuses on the oil and gas supply chain. It aims to emphasize the prevention of defects and reduce variation and waste from service providers.

Meeting the requirements laid out by ISO/TS 29001:2011 ensures standardization and consistency across the sector and improved assurance in the supply of quality goods and services from providers. This is particularly important when the failure of goods or services have severe ramifications for the companies and industries involved.

To find out more about these products and services, please visit the website here.

ABS, the leading provider of classification services to the global offshore industry, has granted Mitsui Engineering & Shipbuilding Co. Ltd. (MES) approval in principle (AIP) for a floating production, storage and offloading (FPSO) vessel design and an epoch-making construction concept.

This work is the result of an ABS/MES joint development project that began in March 2015. The "noah-flex modular design" for the FPSO and the flexible construction procedure, "noah-flex modular construction," were granted AIP on 15 September.

"ABS is working with industry to develop and employ new technologies," says ABS Chairman, President and CEO Christopher J. Wiernicki. "To effectively support Class of the Future, ABS has to provide the services the industry needs to make adjustments as operating conditions and markets change. Granting AIP to new technologies is an essential element of that future."

"ABS is one of the world's leading classification societies with excellent technology and a wealth of know-how in the offshore industry," says MES General Manager Dr. Taketsune Matsumura. "MES recognizes that ABS is our dependable partner and plays an indispensable role in developing and realizing such an epoch-making concept as our "noah-FPSO Hull."

The noah-flex modular construction processes consists of multiple steps that take place in parallel to shorten the construction time efficiently, with keel laying marking the commencement of construction. The first step of the project is FPSO design and hull construction, including propulsion and relevant machinery equipment/systems, which will be carried out by MES, Japan while construction of the oil storage component takes place at another yard, outside Japan for example. Following this process, the topside facilities will be subsequently/simultaneously fabricated in the different/the same shipyard and installed on the elongated hull, after which the completed FPSO will move to the specified operation site for hookup and commissioning.

The FPSO design will be reviewed for compliance with the ABS Rules and applicable International/National Regulations to make sure the unit is in full compliance, particularly when executing transits from one shipyard to another during construction.

"ABS recognizes that working with industry to advance technology is critical," says ABS Special Advisor Ken Tamura. "Engaging in this project with Mitsui provided ABS the opportunity to help shape the future of vessel construction."

Last week was 20 years since the start of oil production from the Troll field. The 20 year-old can look back on enormous wealth, with 1.56 billion barrels produced so far and NOK 460 billion in income.

Troll oil is the impossible made possible. Only a few believed in extracting the thin oil zone at Troll, and through a burning desire to make it happen, determination and innovation, Troll oil became reality,” says Øivind Dahl-Stamnes, head of Troll production.

Determination and innovation in reservoir technology, drilling, well and seabed technology and professional and systematic operations have taken Troll Oil to where it is today: Norway's biggest oil producer the last three years.

“Troll oil is a story that summarizes the best our operations and the opportunities on the Norwegian continental shelf,” Dahl-Stamnes continues.

A well technology puzzle

The Troll oil and gas adventure started with the awarding of the fourth licensing round in 1979. On 17 July 1979, Borgny Dolphin started exploration drilling, and four months later Troll was a fact.

A thin oil-bearing layer stretches across the entire field, but is only viable in two provinces in Troll west. The oil is produced using 15 seabed frames with a total of 121 well slots linked to the floating production platforms Troll B and Troll C.

The greatest challenge when planning the field was to develop technology to extract the thin oil zones without the wells producing too much gas. Technology was challenged and resolved, and in many ways Troll has been groundbreaking in drilling and well technology.

All of the production wells at Troll oil are horizontal wells. This means drilling in two stages, initially down to the reservoir which is 1,600 meters below the seabed, and then up to 5,500 meters horizontally into the reservoir. Most of the wells are so-called branch wells, which mean that they have two or three horizontal sections that are gathered at a crossroad in the reservoir.

Huge wealth


To date 200 wells have been drilled around Troll B and C, which combined have produced 1.56 billion barrels of oil. Troll oil has been Norway's largest oil producer for the past three years. We still have great ambitions for production, and are stretching for 2.1 billion barrel mark in the field's lifetime. The current recovery rate for oil is 40%, with a goal to reach 52%. The Troll oil adventure alone has generated an estimated NOK 460 billion in income, with investments so far of around NOK 100 billion.

The oil is transported to Mongstad, from Troll B through the Troll Oil Pipeline I (completed 1995; 16" diameter, 85 km length, transport capacity 42,500 m3/day), and from Troll C through the Troll Pipeline II (completed 1999; 20" diameter, 80 km length, transport capacity 40,000 m3/day). Associated gas goes to Troll A.

In response to the decline in crude oil prices since mid-2014, the number of active offshore rigs has declined worldwide, dropping close to 20%—304 offshore rigs were operating in August 2015, down from 377 in August 2014. During this period, the number of active offshore rigs in the U.S. Gulf of Mexico (GOM) dropped more rapidly, falling by 46%. Over the past 15 years, the U.S. GOM's share of active offshore rigs worldwide has declined significantly—from almost half of all active offshore rigs worldwide in 2000 to less than 20% since 2008.

Source: U.S. Energy Information Administration, based on Baker Hughes Inc.

In the U.S. GOM, technology advancements accelerated the development of the deepwater (areas where the water depth is greater than 1,000 feet). The move to deeper waters prompted the departure of rigs operating in the shallow waters of the U.S. GOM. Natural gas prospects in the U.S. GOM have also become less profitable, as the largely shale-driven increase in onshore natural gas supply contributed to decreases in U.S. natural gas prices. The number of active offshore rigs in the U.S. GOM declined from 122 in January 2000 to 41 in January 2010, before falling to 19 in June 2010 following the Deepwater Horizon offshore explosion and blowout. The U.S. GOM active offshore rig count recovered to 57 by December 2014, and currently the number is 33.

From 2000 to 2006, the share of active rigs operating offshore in Asia Pacific, the Middle East, and Latin America grew significantly. That share remained steady over the past decade. The expansion of offshore drilling in India and China largely accounted for the growth in offshore rigs in the Asia Pacific region. During the early 2000s, Qatar and Iran accounted for much of the growth in active offshore rigs in the Middle East, with Saudi Arabia accounting for a large portion of the regional growth since 2006. Mexico accounted for the growth in active offshore rigs in Latin America in the early 2000s, as national oil company Pemex increased its offshore activity to arrest declining production from aging fields.

Since 2006, Brazil has been responsible for much of Latin America's growth. Most of the more recent growth in active offshore rigs outside the United States has occurred in Africa. Angola and Nigeria account for much of the growth in the region after 2010. Angola has more than 10 offshore oil projects expected to come online within the next five years. Nigeria's offshore activities have been focusing on the deepwater and ultra-deepwater; at least three deepwater projects are in development and are projected to come online within the next five years.

Shell Nigeria Exploration and Production Company Ltd (SNEPCo) has announced the start-up of production from the Bonga Phase 3 project.

Andrew Brown, Shell’s Upstream International Director, said: “This new start up is another important milestone for Bonga, adding valuable new production to this major facility.”
 
Bonga Phase 3 is an expansion of the Bonga Main development, with peak production expected to be some 50,000 barrels of oil equivalent. This will be transported through existing pipelines to the Bonga floating production storage and offloading (FPSO) facility, which has the capacity to produce more than 200,000 barrels of oil and 150 million standard cubic feet of gas a day.



The Bonga field, which began producing oil and gas in 2005, was Nigeria’s first deep-water development in depths of more than 1,000 meters. Bonga has produced over 600 million barrels of oil to date.

The Bonga project is operated by SNEPCo as contractor under a production sharing contract with the Nigerian National Petroleum Company, which holds the lease for OML 118, in which the Bonga field is located. SNEPCo holds a 55% contractor interest in OML 118. The other co-venturers are Esso Exploration & Production Nigeria Ltd (20%), Total E&P Nigeria Ltd (12.5%) and Nigerian Agip Exploration Ltd (12.5%).

The Bonga North West development began producing vital energy resources in August 2014. The field is located around 120 km off the coast of Nigeria in the Gulf of Guinea at a depth off more than 1,000 meters (3,300 feet). All six wells (four oil producing and two water injection wells) are now completed and on stream, contributing more than 40,000 barrels of oil equivalent at peak annual production. This is transported by a new undersea pipeline to the upgraded Bonga floating production, storage and offloading facility.

Deep Down, Inc. (OTCQX: DPDW) ("Deep Down"), an oilfield services company specializing in complex deepwater and ultra-deepwater oil production distribution system support services announced it has received the largest order in the company's history valued at $13 million directly from a super-major operator.

This order includes one phase of new systems and equipment to be delivered in 2016 for installation in the Gulf of Mexico. The project is structured to ensure a continuous cash-positive position for the company.

Ron Smith, Chief Executive Officer of Deep Down, Inc. stated, "Receiving an order of this magnitude, during the current industry downturn, is a major vote of confidence in our ability to continue providing innovative solutions for our customers. We are humbled by the trust placed in us and are well prepared for the work ahead."

Mexico needs to attract significant interest to salvage a bidding round hampered by delays and low oil prices, with Phase 4 of the current Round 1 licensing process offering the country’s first deepwater assets, says research and consulting firm GlobalData.

The company’s latest report* states that a total of 13 exploration blocks will be open for bidding, together with several deepwater discoveries, with the general expectation that the assets will be offered under a royalty/tax contract called a license.

Adrian Lara, GlobalData’s Senior Upstream Analyst, says that evolutionary evidence from shallow-water terms suggests that the Mexican government is likely to change the adjustment mechanism to reduce the maximum additional royalty rather than accepting lower bids.

Lara explains: “To account for higher costs and exploration risks in deepwater areas, the additional royalty will need to be lower than that envisaged onshore.

“While this would ease the overall tax burden for potential investors, the government may still be able to mandate a reasonable minimum additional royalty rate.”

GlobalData’s report also found that exploration and production companies with over 1.6 million barrels of oil equivalent per day of production may no longer be restricted from partnering, and changes to unpopular corporate guarantee rules are also being considered.

Despite these attempts to make the current phase more attractive, Round 2 is expected to be more popular amongst bidders.

Lara adds: “Many companies are happy to wait to invest in Mexico if the Round 1 terms are not right, as a number of blocks in the Perdido area for Round 2 are possibly more attractive than those on offer this time around.

“The more important element of licensing in Round 1 is the farm-out of deepwater discoveries Exploratus, Trión and Maximino in the Fold Belt, which could contribute production within a much shorter time frame. Outside of the farm-outs, the government only risks the political capital it has invested if the terms are deemed unattractive,” the analyst concludes.

*Mexico’s Round 1 to Rebound with Deepwater Bidding

On behalf of the Peregrino license partners, Statoil is awarding a contract to Wood Group to provide four-year operations and maintenance for our two wellhead platforms (Alpha and Bravo) and modification services for both units and the FPSO Peregrino.

A well head platform on the Peregrino field (Photo:Statoil)

The contract’s scope includes offshore services and covers all production processes and equipment except drilling services and introduces a new operating model for the field, as for the first time the company is bundling all these services in one single contract in order to boost integration and simplify the contract management.

“We have decided to group these contracts in line with our corporate strategy of simplification, cost optimization and production efficiency. We have been working closely with Wood Group in Peregrino field and we look forward to strengthening our partnership for the next four years”, says Pål Eitrheim, senior vice president for Development Production International South America and Brazil Country Manager.

Wood Group has been operating the two wellhead platforms since 2009 and has supported the Peregrino project throughout its development.

“The bundling of the contracts will bring significant cost savings to Statoil Brazil, in addition to simplification to our operations. It’s essential to take the best of what the market can offer to us and further strengthen the relationship with our key suppliers”, says Jon Arnt Jacobsen, chief procurement officer of Statoil.

The Peregrino field is Statoil´s first and largest operatorship outside the Norwegian Continental Shelf. It started production on April 2011 and produces today around 90 000 bpd.

The field is located 85 kilometers offshore Brazil in the Campos basin at about 100 meters water depth in licenses BMC-7 and BMC-47. Statoil holds 60% ownership and the operatorship of the field and Sinochem the remaining 40%.