Effective as of July 16, ConocoPhillips for its convenience provided a notice of termination for the three-year ENSCO DS-9 drillship contract. Under the terms of the contract, ConocoPhillips is obligated to pay Ensco termination fees monthly for two years equal to the operating day rate of approximately $550,000, which may be partially defrayed should Ensco re-contract the rig within the next two years and/or mitigate certain costs during this time period while the rig is idle and without a contract. ConocoPhillips is also contractually obligated to reimburse certain costs that Ensco incurs due to the termination of the contract for ConocoPhillips’ convenience. Given these contract terms, Ensco does not anticipate a material negative impact to its financial results for 2015 and 2016 as a result of this termination.

ENSCO DS-9 was recently delivered and had been scheduled to commence its initial drilling contract for ConocoPhillips in the fourth quarter of this year.

In the beginning of May, the crew on Maersk Discoverer reached a great milestone when they finalized their latest well two months ahead of time. The well was another East Nile Delta success for BP, discovering 50 m of gas pay in high-quality Oligocene sandstones. On May 5, Maersk Discoverer completed the deepest well ever drilled in Egypt and the longest ever drilled in the Mediterranean Sea. What makes the well an even greater success is that it was drilled in 234 days, which was a staggering 62 days ahead of BP’s AFE target, thus creating a substantial cost saving. “The strong performance is a result of the dedicated use of the ‘Plan Do Study Act’ methodology in the planning and execution of the work. Also, a structured approach to applying lessons learned from the previous wells Geb and Salamat played an important role,” says Rig Leader Allan McColl.

Observation studies optimized operational procedures

Allan McColl also highlights the strong focus on actively using observation studies to optimize operational performance as a key driver in continuously improving the operational procedures. An example of this was how the auxiliary well centre was used as a "test bed" to break the BHA (Bottom Hole Assembly) handling process into small clearly defined optimized steps. Following a micro KPI process there was a forty five minute time saving on the critical path by integrating the lessons learned. This benefit was then applied on subsequent occasion of handling the BHA.

Another great achievement that significantly contributed to beating the AFE target was BOP reliability. Thorough maintenance of the BOP prior to the Atoll well and involvement of BP and Maersk Drilling Technical Authority teams in evaluating equipment risk assessments enabled the team to keep the BOP functioning on the wellhead for no less than 201 days.

A fruitful collaboration with BP

The success on Atoll marks another milestone in the collaboration between BP and Maersk Drilling in Egypt. “After all the effort everyone on the BP/Maersk Drilling team has put into building a strong joint performance culture this was a very well deserved achievement that everyone should be very proud of” says Unit Director Thomas Falk. He continues: “We have shown BP what we mean when we talk about jointly creating value and we look forward to continuing our discussions with BP on how we mutually benefit from this in our drilling contracts.”

What is a bottom hole assembly?

A bottom hole assembly (BHA) is a component of drilling equipment. It is the lower part of the drill string, extending from the bit to the drill pipe. The assembly can consist of drill collars, subs such as stabilizers, reamers, shocks, hole-openers, and the bit sub and bit.

The characteristics of the BHA help to determine the borehole shape, direction and other geometric characteristics.

The BHA is used to help the drilling process; the proper selection of the right BHA go a long way in ensuring high rate of penetration and thus helps drill quickly and efficiently.

An industry forum that addresses challenges in subsea integrity management is being extended for a further three years with backing from global oil and gas operators.

Phase II of the The SURF IM Network is led by Wood Group Kenny with support from the Industry Technology Facilitator (ITF). Phase 1 was launched last year, supported by an industry wide group of 14 operators and has been extended to run on an annual subscription basis through to 2018 with an expected project value of around £300,000.

The Mad Dog field complex in the US Gulf of Mexico

The SURF IM Network facilitates face-to-face and virtual forums for knowledge sharing and delivering solutions to subsea integrity and reliability challenges, focusing particularly on subsea hardware.

Kieran Kavanagh, Technology Development Director at Wood Group Kenny said: “This successful joint industry project focuses on knowledge sharing and finding solutions to shared challenges in subsea integrity. The Network represents a significant collaboration among its participants to provide solutions that will help to reduce risk, improve reliability and minimize life-of-field costs in the subsea industry and we’re very happy to be working with participant operators to enable this.”

Dr. Patrick O’Brien, CEO of ITF added: “Taking a standardized approach to complex subsea integrity issues that are common across the industry can help to drive efficiencies whilst creating a safer operating environment, so the Network is a win-win for all involved. It is a great example in the current climate of operators collaborating to support the development of effective and cost efficient means to inspect subsea facilities that are being installed in continually increasing water depths and longer step-out distances.”

In Phase I, progress was made in understanding the issue of control system module reliability and the outcomes of a comprehensive participant survey was presented to subsea suppliers to highlight integrity challenges and find ways to enhance reliability for the future.

The SURF IM Network follows on from a Wood Group Kenny Joint Industry Project (JIP) facilitated by ITF, on integrity management of subsea, umbilical, riser and flowline systems that identified key failure mechanisms, investigated inspection and monitoring technologies and gaps, and developed best practice guidelines for the integrity management of subsea facilities.

Statoil, on behalf of the Johan Sverdrup license, has awarded Samsung the contract for decks for both the process and riser platforms. The total contract value is NOK 7 billion.

The contract is a fabrication contract (FC) of decks for the process and riser platforms. Aker Solutions has previously been awarded engineering work and purchase of equipment packages for the two aforementioned decks.

The function of the process platform, which weighs approx. 26,000 tons, is to ensure stabilization of the oil and processing into rich gas.

The riser platform, which weighs approx. 22,000 tons, will serve oil and gas exports, water and gas injection, as well as any future connections. The power cable from onshore also ends at this platform, where the current is transformed from direct current into alternating current for further distribution to the field centre.

The platform deck will be manufactured at the Samsung’s shipyard in South Korea.

"Johan Sverdrup is a large puzzle in which many suppliers must deliver with precision, quality and on time in order for us to start production towards the end of 2019 and this contract is yet another important milestone for the Johan Sverdrup project. Samsung has extensive experience in manufacturing such installations and we already have a good collaboration with the supplier. They have provided a competitive bid in a tough international competition," says Margareth Øvrum, executive vice president for Technology, projects and drilling at Statoil.

With this latest award, all contracts for the four platform decks have been awarded. The decks for the drilling platform and accommodation platform have already been awarded to Aibel (EPC) and Kværner Stord (EPC). In addition, 65% of the equipment packages have so far been awarded to suppliers with Norwegian billing addresses.

"Johan Sverdrup will be of major significance to the whole of society for at least 50 years into the future. We now have in place a broad and strong team in the supplier industry to construct the decks for the four platforms. This provides the most optimal conditions for project delivery in terms of quality, time and cost," says Øivind Reinertsen, project director of Johan Sverdrup field development.

Facts Johan Sverdrup


The investment costs for phase 1 of the Johan Sverdrup development are estimated at some NOK 117 billion NOK (2015 value). Recoverable resources are projected at between 1.4 and 2.4 billion barrels of oil equivalent.

The development concept for Johan Sverdrup phase 1 will consist of four installations, including a utility and accommodation platform, a processing platform, a drilling platform and a riser platform, in addition to three subsea templates for water injection.

The platforms will be bridge-linked. The project aims at a recovery rate of 70% for Johan Sverdrup.

The Johan Sverdrup partnership consists of Statoil, Lundin Norway, Petoro, Det norske oljeselskap and Maersk Oil. The partnership has recommended Statoil as the operator of all field phases.

Overall main contracts at a value of more than NOK 27 billion and more than 45 equipment package contracts at a value of NOK 3.5 billion have been awarded to suppliers with Norwegian invoice addresses.

ARKeX Ltd. has announced it has been awarded the first G&G oil and gas exploration permit by the Bureau of Ocean Management (BOEM). The ARKeX survey will acquire an airborne broadband gravity and magnetic survey over Outer Continental Shelf (OCS) blocks offshore the US East Coast. The broadband gravity system utilizes a Full Tensor Gradiometer (FTG) which will remotely map geological structures, potentially revealing the location of billions of barrels of untapped oil and gas reserves. The ARKeX survey will be acquired in three phases covering nearly 150,000 square km between Virginia and South Carolina.

This large, regional survey will provide a wide bandwidth and high signal-to-noise ratio data set which will become a valuable and long lived component of the exploration knowledge base. It will contribute not only to the assessment of hydrocarbon prospectivity, but also to the optimization of subsequent exploration activity, to the efficient construction of accurate subsurface models and to the understanding of the dynamic structural geology of the region. The measurement techniques employed are completely passive, utilizing no energy source, such that the environmental footprint is only that of a small aircraft.

Jim White, President of ARKeX said, “ARKeX is very proud to be the recipient of the first geophysical survey permit to acquire data in the Atlantic OCS in more than 30 years. The data will contribute to the positioning and design of future exploration programs, a responsible planning approach which ensures that exploration methods such as marine seismic acquisition are deployed in the most effective and efficient way possible.”

The new data will be integrated with existing complementary geophysical and geological data including 2D seismic, bathymetry and satellite imagery to develop geological understanding of the area.

The ARKeX survey will be acquired in anticipation of BOEM’s five-year OCS oil and gas leasing program. Acquisition is expected to commence Q4, 2015.

Subsea 7 has announced the award of four contracts by Chevron Australia Pty Ltd ('Chevron') and INPEX Operations Australia Pty Ltd ('INPEX' - as operator of the Ichthys LNG Project), for the engineering, procurement and construction of an Emergency Pipeline Repair System (EPRS) to be used offshore Australia.

This EPRS project consists of developing a process of repair, including both equipment and contingency procedures, to support the Chevron-operated pipelines and INPEX's Ichthys pipeline off the North and Northwest coasts of Australia. These pipelines are located in various water depths of up to 1,350 meters and are up to 44" in diameter. The contracts comprise design, fabrication and procurement of repair equipment and development of repair methodologies and procedures that will be available during the life of the Chevron and INPEX operated assets.

Project management, engineering and procurement will commence immediately from Subsea 7's office in Perth, Australia, with support from Subsea 7's intervention and autonomous system specialists in Aberdeen. Site integration testing is due to be completed by 2017.

Stephen Steele, Vice President, Life of Field, said: "This award reinforces our position at the forefront of intervention and repair technologies and showcases one of Subsea 7's key capabilities in the area of Life of Field services. We look forward to continuing our relationship with both companies."

Statoil and its partners have submitted an amendment to the Plan for Development and Operations (PDO) for the Gullfaks license to the Ministry of Petroleum and Energy for phase 1 of the Shetland/Lista development.

Ivar Aasheim, head of field development on the Norwegian continental shelf, submitting the amendment to the PDO for the Gullfaks license to Minister of Petroleum and Energy, Tord Lien, on 30 June. (Photo: Ole Jørgen Bratland - Statoil)

Phase 1 of the development is expected to add 18 million barrels of oil equivalent, and will help increase the resilience of the area for continued operation of the Gullfaks platforms in the North Sea.

“Targeted efforts are underway to cut costs and increase the profitability of our projects. By utilizing the existing infrastructure we manage to recover new resources at a lower cost, thus sustaining profitable production and long-term activities on the Norwegian continental shelf (NCS),” says Ivar Aasheim, senior vice president for field development on the NCS.

The development concept is based on reuse of existing wells (a total of 15) from the Gullfaks platforms, and will not require any new infrastructure. The profitability of the project will thus be very good.

Shetland/Lista has been producing under a test production license since 2013. The submitted plan defines the more long-term development of these resources. This, however, is only the first phase of the development, which involves depressurization down to bubble point pressure in the reservoir.

“Gullfaks has been a unique industrial venture. Since first oil in December 1986 the field has produced more than 2.56 billion barrels of oil and exported more than 70 billion standard cubic meters (sm3) of gas,” says Kjetil Hove, senior vice president for Operations West, Development and production Norway.

“The current recovery rate on the main Gullfaks field is 59 percent, and with a productive life towards 2036 our aim is to further increase this rate,” Hove says. Shetland/Lista will add new valuable barrels. Investment costs are estimated at some NOK 900 million.

Statoil continues its efforts to realize the next phase based on pressure maintenance. This is expected to significantly improve the recovery rate for Shetland/Lista.

The Shetland Group and Lista Formation have with different properties compared with the deeper deposits of the Brent Group, where the main Gullfaks reservoirs are located. The producing interval in Shetland/Lista consists of thin limestone beds that are fractured and thus contribute to good productivity.

Indications of hydrocarbons in the Shetland Group/Lista Formation have long been known. Good productivity was initially established in December 2012 and has been confirmed through perforation in another three existing Gullfaks wells. This has warranted commercial development of the play.

Reducing expenditure while continuing to improve safety and reduce risk is a key driver for the oil and gas industry especially in today’s cost constrained environment. DNV GL and ExproSoft are now joining forces to offer a risk based approach to testing barrier valves in subsea completed wells applicable worldwide. The objective is to reduce both downtime and risk related to shut-in and restart of wells in addition to substantial cost savings.

“In Norway, today’s current prescriptive approach to well testing can result in up to 3 days lost production per test, equivalent to US$10M per asset. Changing today’s prescriptive test intervals and leak criteria to a risk and reliability-based approach, will achieve substantial year-on-year cost savings for operators in Norway and elsewhere,” said Kjell Eriksson, Regional Manager - Norway, DNV GL - Oil & Gas. “Our experts can use established methodologies from the process industry and safety systems to reduce the number of shut-ins and well downtime, thus lowering the need for expensive interventions and work-overs. All this can be attained while maintaining acceptable risk levels and meeting regulatory requirements.”

Currently, the NCS regime refers to NORSOK D-010 for well barrier testing and testing frequencies and leak criteria for well barrier valves are determined by API 14B/ISO 10417. DNV GL and Exprosoft will undertake a project to develop the risk based approach which will identify failure modes and causes, failure rates, analyze the consequences, establish a risk picture and translate the results into a recommended test frequency. Further, a method to develop risk-based leak acceptance criteria may also be an outcome of this work. The results can be applied globally and will be available in Q1 2016.

DNV GL and ExproSoft‘s strategic cooperation and partnership agreement brings together ExproSoft’ s WellMaster, the world’s largest repository of reliability data for wells based on more than 40,000 well years of historical data, with DNV GL’s risk management expertise. “For an offshore platform with 25 wells producing 50 000 barrels a day, the average annual intervention cost is $26 Million,” said ExproSoft’ s CEO, Odd Are Svensen. “We are looking forward to working closely with DNV GL to combine our equipment reliability services with DNV GL’s risk management expertise to reduce intervention cost.”

Leading oil and gas operators in the US, UK and Norway use and share reliability data throughout the well’s lifecycle globally, and experience increased uptime, reduced cost (CAPEX and OPEX), and improved understanding of risk and failures, through access to the WellMaster Reliability Management System (WRMS) from ExproSoft.

DNV GL, the technical advisor to the oil and gas industry, has been selected by Wintershall Norge AS to provide a frame agreement for global inspection services for its developments offshore Norway. The overall contract is expected to exceed NOK 10 million (approx USD1.2 million).

The term of the contract is five years, with an option for two, two-year extensions and covers all Wintershall’s projects on the Norwegian Continental Shelf (NCS). It will initially be used for the ongoing Maria development.

DNV GL will perform inspection, test and surveillance activities on a worldwide basis as instructed by Wintershall Norge AS. The scope of services includes: review of the Inspection and Test Plan (ITP), examination of materials, products, manufacturing processes, work procedures and/or services at Wintershall’s contractor’s premises. DNV GL will also examine contractor’s procedures, documents, quality performance and compliance with governing standards and specifications.

The frame agreement will be coordinated by the DNV GL Stavanger office with resources from the Inspection Division.

“Wintershall Norge AS is a new and important operator on the Norwegian Continental Shelf,” said Kjell Eriksson, Regional Manager – Norway, DNV GL - Oil & Gas. “We are involved with the Maria field across several assignments and this agreement for all Wintershall developments globally will further strengthen our relationship. It reinforces the high quality and value of our broad range of inspection services and expertise to the oil and gas industry and our ability to deliver services to meet project timelines and budgets.”

The frame agreement is now underway and inspection and surveillance work is planned to be carried out across a number of locations including Germany, Italy, Greece, Norway and Malaysia, where subsea equipment components and structures will be manufactured.

DNV GL is also the sole supplier for the combined role of Independent Verification Body (IVB) and Third Party Design Verification scope for the subsea, umbilicals, risers and flowlines (SURF) part of the Maria field development project. The contract is expected to run until the end of 2018, with a potential value of 30 million NOK (approx USD3.95 million).

The Maria oil discovery is located in 300 to 350m of water in the Haltenbanken region of the Norwegian Sea. Maria will be developed using a subsea facility tied via rigid flowlines and flexible risers to Kristin with gas lift being supplied from Åsgard B via Tyrihans and sulphate reduced sea water supplied with injection pressure from Heidrun. The discovery is expected to produce around 188 million barrels of oil equivalent oil and gas. First oil is planned in Autumn 2018.

Technip Samsung Consortium was awarded two contracts by Shell for the Browse floating liquefied natural gas (FLNG) project in Australia, operated by Woodside(1).

The Browse project covers the realization and installation of three FLNG units to develop the Brecknock, Calliance and Torosa fields in the Browse Basin, 425 kilometers North of Broome, Western Australia. The Browse project will capitalize on Shell's FLNG experience, as well as on Woodside's offshore and subsea development expertise.

The first contract awarded to the Technip Samsung Consortium covers the front-end engineering design (FEED) elements of the Browse FLNG project, taking into account the composition of the gas, local weather conditions and factors specific to each of the three fields. This contract was immediately novated by Shell to Woodside as operator.

The second contract covers the engineering, procurement, construction and installation of the three FLNG units of the Browse project. This contract is subject to the final investment decision from the client at the end of the FEED.

The Browse project will benefit from insights brought together by both Shell and Technip Samsung Consortium from the design and construction of Shell’s Prelude FLNG facility and aims at maximizing the replication of Prelude FLNG for the three FLNG units of the Browse project.

Nicoletta Giadrossi, President Region A(2) of Technip, stated: "We are proud to have been awarded this contract which will associate the know-how and expertise gained on Prelude FLNG by our teams, while reinforcing our partnership with Samsung Heavy Industries." Nello Uccelletti, President Onshore/Offshore of Technip, commented: “While FLNG represents a breakthrough in the industry, Technip’s teams worldwide have played a key role in this technology since its inception by bringing together our unique combination of expertise - not only in floating units, but also in subsea developments and liquefaction facilities. Today, we are glad to continue to strengthen our relationship with Shell and Woodside and confirm our FLNG leadership.”

(1)The Browse Joint Venture participants are Woodside Browse Pty Ltd, Shell Australia Pty Ltd, BP Developments Australia Pty Ltd, Japan Australia LNG (MIMI Browse) Pty Ltd and PetroChina International Investment (Australia) Pty Ltd.

(2)Region A is one of Technip’s regions comprising Western Europe, Africa and India.

Further expansion of facilities for the offshore industry at deep-water Lerwick Harbour underlines the Port Authority’s confidence in the sector’s future, with three development projects, costing around £30 million and including 880 meters of additional quays, on schedule.

NYC-based PIRA Energy Group believes that $60 oil is not enough: demand growth will outstrip supply growth without higher prices. In the U.S., the stock surplus continues to sharply narrow. In Japan, runs rise, crude and product stocks build. Specifically, PIRA’s analysis of the oil market fundamentals has revealed the following:

$60 Oil Is Not Enough: Demand Growth Will Outstrip Supply Growth Without Higher Prices

More than ever, the divide over where oil prices are heading in the future is driven by diverging views on supply costs. If you're one who believes that there will be very large quantities of shale oil (or light tight oil) available at a cost under $60/Bbl, enough to meet demand growth and offset depletion of existing production, then prices need not rise from current levels. Alternatively, if you believe that shale volumes will not be sufficient and higher-cost supplies, including oil sands and deepwater, will be required to balance global supply and demand, then a rise in price is likely required.

U.S. Stock Surplus Continues to Sharply Narrow

This past week’s 6.7 million barrel overall inventory decline sharply contrasts with last year’s 5.2 million barrel inventory build for the same week. The year-over-year stock surplus decreased by 12 million barrels to 128 million barrels, down from 177 million barrels at the beginning of April.

Japanese Crude Runs Rise; Crude and Product Stocks Build

Crude runs rose for the second straight week and crude imports recovered from low levels, which led to a sizable 3.7 MMBbls stock build. Major product demand performance was weaker and finished product stocks posted a build of slightly less than 1 MMBbls. The indicative refining margin remains very good. Light product cracks eased slightly while fuel oil cracks were a bit stronger.

Update on Russia Shale Oil Development

Interest in developing Russia's enormous shale oil was riding high in the last few years until the West imposed sanctions over the Ukraine crisis a year ago. Development of shale oil, which is specifically targeted by western sanctions, has slowed substantially. Activities in a number of JVs that have been formed with Western partners, notably between Rosneft and Exxon, Statoil and BP, Lukoil and Total, and Gazprom Neft and Shell, were put on hold. Efforts to replicate the shale boom in the U.S. have also hindered by the collapse of oil prices over the past year.

Financing Not a Major Concern for Most U.S. Independent Producers in Low Oil Price Environment

In the current low oil price environment, cash flow generated by U.S. independents has gone down, debt has increased and debt ratios (i.e. debt/EBITDA) have gone up. However, debt ratios are still acceptable for most U.S. independents, major debt repayments are not due for a few more years, and several companies have mitigated the downside by hedging future oil production. In addition, there is plenty of money available to be lent, interest rates are still low, it is fairly simple to issue new shares, and companies that try to sell assets to maintain liquidity are finding buyers. Therefore, financing is not a major concern for most U.S. independents. There are exceptions and some smaller and highly leveraged producers have had to restructure or declare bankruptcy.

U.S. LPG Prices Rebound

Prices rebounded strongly last week, as brine issues at Lonestar’s Mt. Belvieu storage terminal were seen as transitory and not endemic of a larger containment issue. July propane futures at the Texas market center rallied 10%, while butane, which has been unfairly dragged lower by C3 in recent weeks, jumped 14% to 57.2¢/gal by Friday’s settle. Ethane prices were mostly unchanged around 19¢/gal.

Inventories Drop to the Lowest Level Since January 2

U.S. ethanol production soared to 994 MB/D the week ending June 19, the highest level ever reported in the DOE's weekly supply report. Inventories declined by a whopping 878 thousand barrels to 19.8 million barrels, the lowest since the week ending January 2.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

Eni has started production of the giant gas field Perla, located in the Gulf of Venezuela in the Cardón IV Block. Perla is the largest offshore gas field discovered to date in Latin America and the first gas field to be brought to production offshore Venezuela.

• The largest offshore gas field in Latin America and the first gas field to be brought to production offshore Venezuela;
• Developed in 5 years only, an industry-leading time to market;
• Will produce 450 million cubic feet of gas per day in 2015 and 1200 million cubic feet in 2020. Eni’s net gas production will reach 40,000 barrels of oil equivalent per day in 2015 and 110,000 in 2020.

Eni has started production of the giant gas field Perla, located in the Gulf of Venezuela, 50 kilometers offshore. The first production well has been opened and is currently in the clean-up phase.

The field is located in the Cardón IV Block operated by "Cardón IV S.A.", a company jointly owned by Eni (50%) and Repsol (50%). Perla is the largest offshore gas field discovered to date in Latin America and the first gas field to be brought to production offshore Venezuela. This was achieved through close and successful cooperation between the Venezuelan Ministry of Petroleum and Mining, PDVSA, Cardón IV and its Shareholders.

Image courtesy: Repsol

Perla currently holds 17 trillion cubic feet (Tcf) of gas in place, which corresponds to 3.1 billion of barrels of oil equivalent (boe), with additional potential. The reservoir consists of Mio-Oligocene age carbonates with excellent characteristics, located at approximately 3,000 meters below sea level, at a water depth of 60 meters. The best wells are estimated to produce over 150 million standard cubic feet per day (Mscfd) each.

The development of Perla has been planned in three phases to optimize time to market and investment pace: Phase 1 (Early Production) has a production plateau of about 450 Mscfd (corresponding to approx. 40,000 boed net to Eni) increased from the 300 Mscfd initially planned, Phase 2 has a plateau of 800 Mscfd from 2017 (corresponding to approx. 73,000 boed net to Eni) and Phase 3 has a plateau of 1,200 Mscfd from 2020 (corresponding to approx. 110,000 boed net to Eni).

Eni CEO, Claudio Descalzi, commented: "Eni has reached another milestone with the production start-up of the Perla offshore field, in line with the timing presented to the market in March during the Strategy presentation. Perla was for Eni one of the most significant start-up projects of 2015, and the today result confirms the validity of our development model that allowed us to reach production in an industry-leading time to market".

The development plan includes four light offshore platforms linked by a 30‘ pipeline to a Central Processing Facility (CPF) located onshore at Punto Fijo (Paraguaná Peninsula) and 21 producer wells. In the CPF two treatment trains have been installed with the capability of handling 150 Mscfd and 300 Mscfd each.

The development of the field, discovered in late 2009, was completed in 5 years, an industry-leading time to market. This excellent performance was achieved thanks to an extensive use of pre-pack modules in the realization of the onshore gas treatment trains, in order to minimize construction works.

Cardón IV signed a Gas Sales Agreement with PDVSA for all three phases, until 2036. The gas will be mainly used by PDVSA for the domestic market.

Eni’s other operations in Venezuela include the Junín-5 heavy oil block (PDVSA 60%, Eni 40%), located in the Orinoco Oil Belt, which holds 35 billion barrels of certified oil in place. Junín-5 production started in March 2013. In addition, Eni holds a 26% stake in PetroSucre, the operating company which operates the offshore Corocoro oil field, (PDVSA holds the remaining 74%). Eni’s current net production in Venezuela is approximately 12,000 boed and is expected to exceed 50,000 boed by year end, mainly due to the increase in production from Perla.

Xodus Group has been awarded a contract for the vibration assessment and analysis on the oil train piping and structures for Zakum Development Company (ZADCO) at Zirku Island, 140km north-west of Abu Dhabi.

The work, valued at over $600,000, will pull in services from Xodus’ process, piping, instrumentation and structural teams. The 24-week project will include a Front End Engineering Design (FEED) scope of work With its advanced oil and gas installations, Zirku is considered the main industrial base for the processing, storage and export of oil from the Upper Zakum, Umm Al-Dalkh and Satah fields.

Steve Hamilton, Xodus Group’s Managing Director for Middle East and Asia

In recent months, Xodus’ vibration engineering team has also won a number of other contracts in the Middle East.

The company secured a three-year contract to deliver rotating machinery condition monitoring services with rotating machinery vibration analysis and risk management.

Xodus has also been awarded work to investigate two vibration issues on Sulphur Recovery Units in Abu Dhabi. The work will be split into two phases: phase one for the site survey vibration investigation and phase two to engineer solutions to eliminate/reduce the vibration concerns once the root cause has been identified.

Steve Hamilton, Xodus Group’s Managing Director for Middle East and Asia said: “We have made a strong start to the year with these contract awards. The team deserves a lot of credit as these wins have been built on the excellent feedback from previous projects.

“Xodus’ seamless integration of services from exploration through production and development can greatly enhance the quality of what we deliver as well as saving valuable project time and overall costs. Our specialist vibration expertise is ideally suited to the challenges currently facing operators in the region.”

Swire Oilfield Services has secured an exclusive five year contract with Weatherford International plc in Brazil.

The contract, providing DNV 2.7-1 cargo carrying units (CCU’s) to the oil and gas service company, was awarded following a year-long tender process and will ensure the safe transportation and storage of project critical equipment offshore.

Worth a seven figure (BRL) sum and running for the duration of five years, this is an important contract for the company in a key growth market where they already employ 85 people in Rio de Janeiro and Macaé, maintaining the firm’s development of its services to help clients in the region deal with increasingly challenging logistics.

Marcelo Nacif, General Manager Brazil, said: “This is a great reward for the team’s efforts in growing the business in Brazil and we are proud to support Weatherford’s activities.

“Swire Oilfield Services has a long established reputation for providing the energy industry with reliable, innovative products and services, and operating the world’s largest fleet of offshore CCU’s enables us to respond quickly to our customers’ requirements.

“Of all the markets we operate in, Brazil in particular is undergoing a period of transformation as it attempts to more than double production by 2020. Our increased focus on research and development to better meet our customers evolving needs will help them to achieve this and improve their operations.”

Bureau of Safety and Environmental Enforcement (BSEE) Director Brian Salerno today announced that BSEE Alaska Region Director Mark Fesmire this week oversaw testing of Shell’s proposed Arctic-ready capping stack system in Puget Sound to ensure compliance with stringent Federal safety standards for oil and gas exploration on the Arctic Outer Continental Shelf. A key piece of Arctic oil exploration containment equipment, the capping stack is used to contain the flow of oil in the unlikely event all primary and backup blowout prevention equipment fails during drilling. It is required to be in position for all of Shell’s potential drilling activities in the Arctic.

During tests last week, BSEE personnel witnessed the deployment and maneuvering of the capping stack off the rear deck of the M/V Fennica to 150 feet of water, which is deeper than Shell’s current well sites in the Chukchi Sea. BSEE confirmed that the capping stack functioned properly under pressures exceeding the maximum expected pressures Shell may encounter in the Arctic. Deployment of the capping stack and stack pressure testing were completed in two separate exercises spanning two days.

BSEE is currently reviewing Shell’s request to drill two exploratory wells in the Chukchi Sea this summer. If BSEE approves the drilling permits, Shell would be required to maintain the capping stack in a ready-to-deploy state on the M/V Fennica, which would be available to respond to a loss of well control within 24 hours.

In addition to containment and engineering observations such as the ones conducted this week, BSEE is overseeing additional on-water oil spill response exercises and drills and on-site inspections of oil spill response equipment throughout the proposed drilling operation. BSEE will use its authority to conduct a variety of equipment inspections and deployment exercises, some of which may be unannounced, to validate the tactics, logistics, resource availability, and personnel proficiency specified and relied upon in the approved plans and permits.