From the Editor Archive Collections

Gulf of Mexico offshore assets The services will be delivered under the global EPMS contract which was awarded by BP in June 2008 for a four year term with an option to extend. The assets covered by the services will include Atlantis, Holstein, Horn Mountain, Mad Dog, Marlin, Na Kika and Pompano. The scope will involve brownfield topsides modifications for these producing assets, as well as topsides work associated with tiebacks executed by the BP GoM Subsea Projects Group. The contract commences immediately and the services will be delivered from WorleyParsons office in Houston’s energy corridor. It is anticipated that the WorleyParsons team will rapidly grow to more than 300 personnel for the term of the contract. The primary focus of the contract is to support BP’s offshore GoM assets safely and consistently in order to deliver technical integrity and long term operating efficiency. Commenting, the Chief Executive Officer of WorleyParsons, John Grill, said: “This award reinforces our commitment to Houston as a major centre for our offshore business. It enables us to deliver the core brownfield capability that we have developed and refined over the past thirty years. We welcome the opportunity to provide high quality EPMS services in order to create long term superior value for BP and its partners.”

In total, the order comprises two overhead-mounted launch-and-recovery systems and two umbilical winch systems to be delivered in May 2010 to the company’s new ROV-support vessel Fugro Symphony, which is expected to enter service in the third quarter of 2010. Øystein Bondevik, sales director for MacGREGOR Offshore division says: “The unique overhead design of these powerful and flexible handling systems will provide Fugro Symphony with the sought-after precision needed to manoeuvre the subsea ROV system onto the seabed and will add valuable deck space in the hangar. ”The combination of the ROV-handling system and the active heave-compensated ROV winch will also expand the vessel’s ‘weather-window’ and will assure operational reliability, accuracy and precision, which are vital elements when working offshore in adverse climate conditions. Furthermore, with these systems installed, the critical splash zone area can be secured because the dual axis dampening technology reduces the load’s movement at this crucial stage. “In addition, the MacGREGOR VHSS umbilical spooling system, which is fitted on the winch, will ensure excellent spooling and full-diameter bending radius of the cable. In turn, the umbilical cable will undergo less ‘wear and tear’, granting it a longer lifespan”. MacGREGOR’s ROV launch-and-recovery system and its umbilical winch technology are components of a broader high-precision subsea load-handling product range that also offers active heave-compensated offshore cranes and module-handling solutions. In addition to the ROV launch-and-recovery systems, Fugro Symphony will also be equipped with a MacGREGOR Hydramarine 150T active heave compensated knuckle jib crane. It is capable of lowering large loads down to a water depth of 3,000m and is due for delivery in November 2009.

On a CPU-based cluster, this process could take anywhere from 2 hours to several days. In an effort to improve this, the team acquired a workstation equipped with an NVIDIA® Tesla™ C1060 GPU Computing processor, based on the NVIDIA CUDA™ parallel computing architecture. In six weeks the OpenGeoSolutions team converted a key portion of their application to CUDA and, as a result, witnessed an order of magnitude increase in performance. "We are measuring speedups from 2 hours to 2 minutes using CUDA and the Tesla C1060," said James Allison, president of OpenGeoSolutions, Inc. "This kind of performance increase is totally unprecedented and in a market where there is great economic value in being able to determine these fine sub-surface details, this is a game changer." "More importantly, the Tesla products essentially give us all a personal supercomputer," Mr. Allison added. "Just one Tesla C1060 delivers the same performance as our 64 CPU cluster, and this was a resource we had to share. This is a huge cost and time saving that has transformed our workflow and boosted our productivity." OpenGeoSolutions provides spectral decomposition and inversion services along with commercial support for an open source seismic processing system called FreeUSP. Several major, independent and national oil companies use FreeUSP software to refine their geological models and locate valuable hydrocarbon reserves.

Covering approximately 250 deepwater OCS blocks (5828km²), the new program named "Discovery" focuses on a relatively underexplored area recently opened for leasing in the Central and Eastern GoM planning areas. PGS will be acquiring the DeSoto Canyon survey using its new and unique GeoStreamer technology. This will be the industry’s first 3D implementation of GeoStreamer yielding higher fidelity data. The PGS Atlantic Explorer will commence the first phase of data acquisition in December 2008 and acquisition of the entire 250 block project will be completed in approx. 9 months. BP America Inc. will be an underwriter for the survey and collaborate technically on the project, focusing on extracting the maximum technical benefit that the GeoStreamer delivers. The project has attracted wide interest from oil companies with lease holdings in the area and those wishing to acquire new acreage or those seeking farm-in opportunities. PGS’ President for the North and South America region, Magne Reiersgard added the following: "The GeoStreamer is the result of several years of research and development in PGS. It combines two different sensors yielding enhanced resolution and better penetration as well as improved efficiency due to deeper tow. The GeoStreamer is particularly well suited to solve the exploration challenges in an area like DeSoto Canyon." Data will be available for the upcoming March 2010 Lease Sale in the Gulf of Mexico.

FMC's scope of supply includes three high temperature enhanced horizontal subsea trees and four subsea wellheads. All equipment will be designed and manufactured at FMC's Dunfermline, Scotland facility. This is the third award FMC has received from Venture in 2008. Previous contracts for Venture's Chestnut and Acorn fields included the supply of two wellhead systems and one subsea tree for each project. The subsea tree for the Acorn field includes a multi-mode fiber optics communication system designed to optimize well productivity and improve the speed and accuracy of data received from the well. "Today's announcement strengthens our relationship with Venture," said Tore Halvorsen, FMC's Senior Vice President of Global Subsea Production Systems. "We are pleased to support them in their commitment to developing oil and gas resources in the North Sea."

Said Mr Charles Foo, Chairman of Keppel Singmarine, “This is the first time that icebreakers meant for the Arctic region are built in the tropics. It also marks Keppel Singmarine’s entry into the flourishing oil and gas market in the Arctic region.” The second vessel, Varandey, will join Toboy in the Barents Sea of Russia where they will help forge passages through the ice for oil tankers plying the Varandey Terminal. Both Varandey and Toboy are designed to work in the harshest environments, equivalent to the height of a grown man, and operating in extreme temperatures as low as -45oC. According to the latest United States Geological Survey, it is estimated that the Arctic may hold as much as 90 billion barrels of undiscovered oil reserves and 1,670 trillion cubic feet of natural gas. This is equivalent to as much as 13% and 30% of the world’s total undiscovered oil and natural gas respectively. Mr Foo said, “The increasing oil and gas exploration and production activities in the Arctic present tremendous opportunities for specialised and robust vessels such as the icebreaking vessels.

Al-Falih, currently executive vice president of Operations, will succeed Abdallah S. Jum‘ah, who has decided to retire after 40 years of service to Saudi Aramco, including nearly 14 years as president and CEO. The Minister noted that Al-Falih has worked for Saudi Aramco for almost three decades and rose to senior management positions in the oil and gas sectors, including exploration and producing, refining and international operations. Al-Falih is in his fifth year as a member of the company’s Board of Directors, he added. Al-Falih commended Jum‘ah for his wise leadership in positioning Saudi Aramco among the world’s top companies and preparing it for the future. He vowed that he will strive to preserve the company’s position as a leader in production and reserves, in technology, and in its capable and productive workforce.

Dockwise Shipping is to transport the drilling rig, Noble Hans Deul, from its new- build yard in China to its first assignment in the North Sea. Jack-up rig Noble Carl Norberg will be moved from West Africa to a new assignment in Mexico. On behalf of CCCC from China Dockwise Shipping will also transport three loads of dredging equipment to Nigeria and Sri Lanka. All projects are for execution in the final quarter of 2008, with total revenues of more than USD 27 million. OKI has been contracted by the EOS / Woodside joint venture to provide float-over hardware on the North Rankin B project. For this contract, OKI is to invest USD 4 million in the world's largest test press (12,000 MT with 2 m stroke), an investment enabling OKI to secure a range of similar offshore marine projects. It will also provide for OKI to expand into several services increasingly sought by clients: rubber molding, fabrication and machining. The contract, largely for execution in 2009, has a value of almost USD 13 million. Andre Goedee, Chief Executive, Dockwise Ltd, said: "Progress in 2008 continues according to plan and we see encouraging signs in our markets as we look ahead into 2009. Our investment in fleet refurbishment and expansion during 2008 has equipped Dockwise well to capture growth opportunities in both traditional and new markets.

In Azerbaijan Saipem has signed with BP Exploration (Caspian Sea) Ltd the Underwater Service Contract Long term Agreement. Saipem will be responsible for the activities required for the inspection, maintenance and repair of the existing BP facilities in the Azeri offshore, including the platforms installed by Saipem in the previous years. The contract has a duration of 5 years, which BP has an option to extend by 2 years. In Brazil, Petrobras has been awarded the contract for the Uruguà-Mexilhão pipeline. Saipem will transport, install and test a 18”, 174-kilometre long gas pipeline in the Santos Basin, offshore Brazil. The pipeline will link the floating production, storage and offloading vessel Cidade de Santos, located in the Exploratory Block BS-500 at Uruguá field, in 1372 meters water depth, to the Mexilhão gas platform in the Mexilhão field in 172 meters water depth. Project activities are scheduled to finish by the end of March 2010. Finally,PDVSA Gas S.A. HAS BEEN awarded Saipem the contract for the Dragon – CIGMA pipeline in the Mariscal Sucre complex in offshore north-east Venezuela. Saipem will transport and install a 115-kilometre, 36-inch gas export line connecting a platform located in the Dragon field to PDVSA's CIGMA complex on the southern side of the Paria peninsula, in the state of Sucre. Marine activities will be mainly carried out by the Semac pipelayer vessel and are scheduled to be completed by the end of 2009.

The company will be based in Abu Dhabi and is employing professional staff for the management, projects & engineering and finance who will be dedicated to assess and evaluate any new opportunities of manufacturing, in a very professional manner. It will form an umbrella business to cater for current joint ventures, licensing agreements and the acquisition of technical knowledge and creating new venture initiatives. The company aims to attract established manufacturing companies who not only boast demand for their products in the Middle East and North Africa (MENA) region but also shares MSE’s commitment and reputation to deliver products and technology of the highest quality and standards. A new management headed by Adel Baobaid as the Vice President, AlMansoori Petroleum Industries, is being created to oversee product development and the manufacturing process as well as enhance relations with current and prospective partners. The business is looking to create any technology or equipment for use in the oil and gas industry from its Abu Dhabi base. AlMansoori Petroleum Industries will be showcasing its capabilities at the largest oil and gas event in the Middle East ADIPEC, which is being staged at the Abu Dhabi National Exhibition Centre between the 3rd and 6th November. Its current manufacturing companies, Global Chemicals, Hilong AlMansoori, Specialized Oilfield Products and Micoda will be exhibiting through AlMansoori Petroleum Industries. Adel Baobaid, Vice President, AlMansoori Petroleum Industries said the company will offer huge benefits for the MENA region. “The energy industry is changing and many companies are looking towards self sufficiency. This company will create that opportunity to manufacture and supply equipment to the region rather than totally depend on international supply. This will not only bring significant economical advantages and exciting career opportunities to the country but it will also help our customers source material at a competitive price with prompt delivery, without compromise to quality and standards, which will give us the competitive edge.”

Millennium Chemicals is part of Cristal Global, the second largest titanium dioxide producer in the World, operating 9 manufacturing plants, spanning 5 continents. In 2008 Millennium Chemicals focused their global business strategy on stability, higher productivity and reduced costs, and Opralog is to be implemented as part of the group’s commitment to continuous improvement. Mike Huntley, Team Leader for Operating Disciplines at Millennium Chemicals Stallingborough, outlined the company’s requirements; “We are introducing an electronic database to manage communications, from the shift operator’s log through to the equipment and process evaluations. Until now we have used a number of different methods to capture this information, including paper logs, spreadsheets and databases. Opralog allows the equipment and process evaluations to be designed so that the operator can recognise and act on the early signs of a problem. The benefits of having consistent data readily accessible throughout the organisation will include improved equipment reliability, particularly with our rotating equipment, together with associated improvements in the areas of HSE, maintenance and operations cost performance”. Speaking of the contract, Infotechnics Business Development Director, Jon Howard, said “We are delighted that Millennium Chemicals have decided to collaborate with Infotechnics to enhance the way in which they operate. Opralog will fulfill Millennium Chemicals need for improved consistency of logs and reports in terms of format and structure. Opralog will also enhance the ability of their operational logs to act as a source of management information by recording key status information on safety, environment, commercial, plant and other issues to support shift handover and production meetings. Millennium Chemicals production plants will also benefit from time saved capturing data, comprehensive audit trails, effective reporting capabilities, and ultimately the fostering of a safer and more efficient working environment through a culture of openness and visibility”.

AMEC and SeaMetric will cooperate to support each other with their respective skills and experience on existing and new projects. For example, AMEC will provide project management and technical support to SeaMetric’s Twin Marine Lifter (TML) projects in Asia and Latin America. Lifting very heavy objects weighing up to 30,000 tonnes, such as offshore platforms at the end of their life, in cost effective and safe manner, is a vital part of the decommissioning process. Adding project management and technical support to ensure the process is successfully completed for our clients across the globe gives this agreement a unique combination of skills. “The market for the decommissioning of offshore oil facilities is huge and working with SeaMetric will enable us to enhance our portfolio of asset support services to provide an integrated “end-of-life” solution, “ said Neil Bruce, Chief Operating Officer of AMEC’s Natural Resources division. “In mature markets, with new independent operators and oil majors requiring new combinations of skills, we are well placed to deliver offshore decommissioning around the world. We have supported many of these offshore assets from their original concept through to design, commissioning and operations and maintenance, which puts us in a unique position to project manage and engineer the end of their life too.” SeaMetric’s Managing Director, Johan F. Andresen added: “Cooperation with AMEC is a major step towards realizing the potential of TML, particularly in the North Sea platform decommissioning market. Support from AMEC will also be of major value as we complete the construction of our TML systems and will strengthen our joint TML operating companies”.

The new plant will more than double the existing production capacity. Located next door to an air separation facility the plant will use liquid nitrogen, a product from the air separation process, to liquefy the natural gas. The scope of Hamworthy’s work includes engineering, procurement, construction, installation and commissioning of a pre-treatment plant, liquefaction system and storage tanks. Hamworthy Gas Systems AS is owned by UK-based Hamworthy Plc and based in Asker outside Oslo, Norway. The company is a leading supplier of small scale LNG production technology and gas processing systems. Better known for its supply of systems and products in the marine and offshore markets Hamworthy Gas Systems also delivers turnkey onshore LNG production plants for its customers, allowing them to bring methane to markets. This then contributes to the increased use of a cleaner and more cost effective source of energy. Øystein Bruno Larsen, Director, Onshore LNG Facilities, said: "Our process know-how and skid-fabrication designs have been successful in securing this contract, which exposes us to the international arena of the fast growing LNG market.” Hamworthy delivered its first onshore LNG production facility in early 2003. This has a liquefaction capacity of 20,000 tons per year and is based on a single-stage reversed Brayton nitrogen cycle. In mid 2007 Hamworthy commissioned its second onshore LNG production facility based on a two-stage reversed Brayton cycle with a liquefaction capacity of 84,000 tons per year. Its efficiency was improved by 35% and through operations it has shown that it possesses a high degree of flexibility and robustness, which is particularly important for offshore producers. The company has now developed onshore plants and LNG FPSO designs with single train capacities in the range of 0.5 to 1 million tons per year. At the other end of the scale, a ‘mini’ LNG plant particularly suitable for the liquefaction of bio gas, and the production of LNG as vehicle fuel, is also under development. Gasum is the sole importer of natural gas and transmission provider in Finland and currently anticipates an increase in Finnish natural gas consumption of 12 TWh (28%) on current level (43.4 TWh) by 2020. The focus of the growth will be on combined heat and power production, with natural gas replacing coal-fuelled production. Gasum is working to increase the use of natural gas as a transport fuel. In recent years Gasum has invested heavily in public natural gas filling stations. Currently there are five filling stations in Finland. The plan is to increase the number of stations to 30 by the year 2010. Finland’s national climate and energy strategy, which is due to be brought before Parliament in late autumn, will also have a major impact on the use of natural gas in Finland.

The application, developed over two years, has a 100% success rate and will help prevent the failure of flexible risers and flexible flow lines, thereby minimising lost production and associated environmental impact of a leak. The daily cost of lost production resulting from a riser failure has been estimated at between €1m and €3m. Aberdeen-based flexlife devised the patented solution to scan flexible risers in situ and detect annulus flooding anywhere along their length – the first time in the 40 year history of unbonded flexible pipe that this has been achieved – while AGR Field Operations has the ROV capability to deliver it through the Neptune system. “AGR Field Operations is proud to have developed the ROV deployable Neptune system, a world first that can deliver a range of truly innovative subsea inspection solutions” said AGR Field Operations Executive Vice President Åge Landro. “The joint objectives of AGR Field Operations and flexlife are to field the first subsea inspection application that can be used for the reliable, in-situ annulus examination of flexible risers and flowlines for the detection of flooding and to reduce or eliminate hydrocarbon leaks and spillage from offshore FPSO oil production facilities due to a breach of flexible risers or flexible flowlines resulting from in-service failure.’’ Flexlife director Carl-Petter Halvorsen said: “This is the first time it has been possible to scan any flexible pipe in situ without access to the end fitting meaning any potential failures can be identified and dealt with more quickly than was possible previously. Neptune is fast, reliable and can go down to 6,000metres so the technology can go anywhere in any environment meaning the potential cost savings and environmental benefits are immense.

The Kvitebjørn rich gas pipeline, which runs from the Kvitebjørn platform in the North Sea to Kollsnes processing plant outside Bergen, was closed on 20 August following the discovery of a minor gas leakage from the pipe. The gas leakage was discovered during a routine inspection of the pipeline in connection with start-up after a scheduled shutdown. The leakage is in the same place as the pipe was damaged last year by a ship’s anchor roughly 10 kilometres from the platform. The pipe was qualified for temporary use in January 2008 pending permanent repairs that were scheduled for summer 2009. StatoilHydro has reassessed various alternative repair solutions and plans to start the repairs to the pipeline at the turn of the year. Given the uncertainly attached to weather conditions in the North Sea at that time of year, it is not possible to say with any certainty how long the repair work will take. If the primary repair solution is successful, StatoilHydro expects production to resume by the end of the first quarter 2009. If it is necessary to change the repair strategy underway, start-up will most probably take place around 1 June 2009. During the period until repairs start, Kvitebjørn will continue with the planned drilling programme as well as continuing with necessary scheduled maintenance work. The Visund field also usually uses the Kvitebjørn pipeline for gas exports. This gas is now being reinjected into the reservoir. Oil production on Visund is being maintained, but at a lower level than usual.

Simon Richardson, Production Manager, for National Grid Grain LNG outlined the company’s requirements from Opralog; “At present work is underway to triple the terminal capacity at the Isle of Grain. This has involved the construction of 3 new state of the art LNG storage tanks, each holding as much as the existing plant and equal in size to the Albert Hall! With this expansion underway and further expansion planned in the next 3 years it was important that we introduce a centralised operational logging system which could be deployed across Grain LNG, primarily to ensure effective communication between the control rooms. Opralog is a robust system which we can tailor to our individual needs by leveraging data already held in other plant information systems. We can therefore ensure that valuable, consistent data is captured and is easily accessible, not only to the control rooms, but across the organisation to those who need it”. Speaking of the contract, Infotechnics Business Development Director Jon Howard said “Opralog will fulfill Grain LNG’s basic requirement to ensure effective communication between the control rooms. It will improve the consistency of the importation plant’s operational logs in terms of format, structure and content, along with enhancing their ability to act as a source of management information by recording key status information. Operational and commercial risk will be reduced as effective data capture and reporting will increase the visibility of abnormal events, which could otherwise go unnoticed. Grain LNG will further benefit from enhanced performance management by time saved capturing data, reduced downtime, comprehensive audit trails and the nurturing of a safer, more efficient environment. We are delighted that National Grid Grain LNG have chosen to work with Infotechnics and we look forward to enhancing the way in which they operate”.

K5F will be the first project in the world to use all-electrically activated subsea equipment (“Christmas Trees”) as opposed to hydraulically operated standard technology. This step change in subsea technology will bring increased system reliability and enhanced environmental performance. Furthermore it will add to Total’s capability of bringing new production from deepwater fields, including frontier areas of the North Sea where Total continues its strategy of investment in exploration and production. Total is the operator of the K5F field, with its partners E.B.N, Dyas B.V., Goal Petroleum (Netherlands) B.V. and Lundin Netherlands B.V. Production began on September 6, 2008, and the field is currently producing approximately 45 million standard cubic feet of gas per day. Production is expected to ramp up to 90 million standard cubic feet of gas per day in the coming months. The development phase included the completion of two subsea wells, and the installation of a 10 kilometre long, 20 cm diameter subsea pipeline which is connected to the existing K6N satellite platform. After treatment, the gas is transported onshore to Uithuizen (Groningen) through the NoordGasTransport pipeline. The K5F development, together with the recent Goal acquisition strengthens the position of Total E&P Nederland B.V. as a major player in the Dutch gas exploration and production industry.

“This is a very important milestone for StatoilHydro. We have worked in Nigeria for 15 years to achieve this remarkable project, and it’s most satisfying to commence production,” says Thore E. Kristiansen, senior vice president and head of INT South Atlantic.

“At plateau production, StatoilHydro expects some 44,000 barrels of equity production a day from Agbami - a substantial contribution to our overall international output,” he adds.

The scale of the Agbami project is massive and the safety record impressive. The project team overcame numerous technical and commercial challenges to deliver first oil.

Water depths descend to1,500 metres. The Agbami floating production, storage and offloading vessel is the world’s largest FPSO.

Designed to store about 2.2 million barrels of oil, the vessel is set to be on location for more than 20 years.

“This marks a watershed in our operations in Nigeria as the huge Agbami field comes into production. We are proud to be a part of this world-class project,” says Helge Håland, managing director, Statoil Nigeria.

The contract is for manufacturing and delivery of 48 kilometres of steel tube umbilicals. The dynamic section of the umbilicals will be made using Aker Solutions' patented carbon fibre rod technology, which is developed specifically for deepwater and ultra-deepwater conditions.

"This is the second time we are delivering our umbilicals to BP's projects in Angola, and we are pleased to build on our solid relationship with them. We are the biggest player in the global steel tube umbilical market and large contracts like these are proof that our technology is a good fit for ultra-deepwater developments," says Raymond Carlsen, executive vice president, Aker Solutions.

The umbilicals will be manufactured and delivered out of Aker Solutions' facility in Moss, Norway. Delivery of the umbilicals is scheduled for Q3 and Q4 2010.

This is the first time that Saipem has been named as the main contractor of a large gas liquefaction (LNG) plant, asserting its reputation as an integrated player, capable of managing large and complex turnkey projects in the high tech market of the LNG sector.

The works for the new Arzew LNG Train (GL3Z) will be completed by the end of 2012.

George Morris, ATP's Chief Operating Officer said, "These recent and existing commitments allow us to maintain our schedule for developing our key properties. We now have secured rigs for our entire 2008 scheduled drilling program and for all but one well of our 2009 drilling program. Our development capital budget includes the cost of all of the 18 well operations to be commenced in 2008 and 2009. These rigs will be used to drill proved and probable undeveloped reserve locations that were on our books in the beginning of 2008, plus additional logged hydrocarbons and significant upside potential not yet on our books at several of our key properties including Clipper, which was acquired earlier this year."

The solution incorporates three synergistic components: diagnostics tools, engineered cement systems, and zonal isolation assurance tool. With this new service Halliburton continues to evolve the cementing operation beyond the conventional cement-design method that predominantly focuses on well-construction activities. This service is an interventionless react-and-respond solution designed to help address the industrywide challenge of the loss of zonal isolation due to changes in the wellbore that can stress the cement sheath and lead to destabilization at any point during the life of the well.

"Up until now, the well-construction industry has focused on cement properties such as cement placement, preventing gas migration and compressive strength," said Tommy Roth, vice president of Cementing, Halliburton's Completion and Production Division. "This approach has been necessary to optimize drilling time but does not account for maintaining zonal isolation for the life of the well. WellLife III cementing service enables zonal isolation over time, even when the well is subjected to various stresses. Halliburton is changing the industry's fundamental approach to cementing."

WellLife III cementing service is designed to stop the flow of unwanted fluid and gas in the annulus at any time during the life of the well, preserving production while reducing or even eliminating costly remediation.

With increased complexities of well designs and harsher environments, the potential loss of cement-sheath integrity resulting in annular pressure and/or the loss of downhole pressure containment will only become a larger issue.

"For years the industry has tended to view cementing as a separate event from well performance," said David King, president, Halliburton's Completion and Production Division. "However, Halliburton has scientifically investigated the potential damage to the cement sheath created by the cumulative stresses in and around the wellbore. We are challenging conventional thinking by taking the stand that it is no longer sufficient to focus solely on achieving a competent cement bond log when the technologies are now available from Halliburton for cementing systems to be designed for years of use and abuse."

The properties, which are located in Atoka, Coal, Hughes and Pittsburg counties, Oklahoma are currently producing approximately 50 million cubic feet of natural gas equivalent per day. The companies anticipate closing the transaction on August 8, 2008.

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “There was substantial industry interest in our Woodford Shale asset package and we are pleased to announce the sale of these properties to BP. This transaction completes another aspect of our asset monetization program and enables Chesapeake to redeploy capital to our Haynesville, Barnett and Marcellus Shale plays and further improves the company’s capital structure. BP has long had a leading position in the Oklahoma natural gas industry and we are very pleased to see its deepening commitment to Oklahoma. We look forward to working with BP on other projects in the future, in addition to current projects such as our Anadarko Basin Joint Venture in which we are drilling a series of Deep Springer wells across a 155 square mile area of mutual interest in Washita County, Oklahoma. Our first well has been logged and looks excellent.”

“This purchase is a strategic entry into an attractive and established shale basin with potential resources of up to 2 trillion cubic feet of gas. It complements our extensive unconventional gas plays throughout North America” said Andy Inglis, BP’s chief executive of Exploration and Production. “This acquisition has the potential to more than double our existing production of over 200 million standard cubic feet per day from our Arkoma operations”. Meagher Oil & Gas Properties, Inc. acted as advisor to Chesapeake.

Claxton Engineering will be supplying subsea risers, interface connections and personnel for drilling and completions operations for five wells on a high-pressure natural gas platform, set in depths of 44 metres, 175 km offshore of Nova Scotia, in the Deep Panuke field.

During Q2, 2009, the equipment will be shipped to Halifax, where Claxton Engineering will prepare it for operations before it is taken offshore. The project is being conducted from a Rowan Gorilla class jack-up rig and drilling is scheduled to commence Q3 of 2009, with Claxton engineers on hand to help run and pull the riser. It is expected that the project will be producing by 2010.

Laura Claxton, Managing Director, Claxton Engineering Services said, “This is a long term, high value contract to be conducted offshore Nova Scotia. This contract marks Claxton's entrance to the North American sector and we have been

selected for this because Claxton can provide a high quality and best value full riser supply service."

This field is located off the coast of Nigeria in Block OML 120/121, at water depths reaching 410 meters.

The contract includes: the engineering, fabrication and installation of close to 20 kilometers of flexible production, water injection and gas injection flowlines and risers, the installation of close to 15 kilometers of umbilicals supplied by the client.

Technip’s operating center in Paris, France, will execute this contract. The flexible flowines and risers will be fabricated by Technip’s Le Trait plant, France, one of the Group’s flexible pipe production facilities.

The offshore installation is scheduled for the summer of 2009 and will be carried out by the Constructor, one of the Technip’s pipelay and construction vessels.

The LaserMethane® mini (LMm) is lightweight and compact, providing users with a long range instrument capable of detecting ppm levels of methane from a distance of up to 100 metres. Not just portable, but truly handheld, the LMm weighs only 600g and measures W70mm x H179mm x D42mm. With advances including automatic ranging, colour LCD, five hour battery, extended temperature range and IP54, the unit complements the previously launched LaserMethane® Detector (LMD) and utilises the next generation of Tuneable Diode Laser Absorption Spectroscopy (TDLAS).

ATEX approval allows the LMm to be used in Zone 1 areas for on-plant use as well as detecting escapes in hard to reach or inaccessible areas such as roof spaces, pipes crossing rivers or roads, and fenced enclosures. This means there is no longer a need for personnel to put themselves at risk by entering suspected escape areas.

The LMm uses an innovative laser diode tuned specifically to the characteristics of methane, and the level of this one gas is then displayed on the ppm.m* readout. The instrument performs a self check on start-up and verifies the operation and calibration of the laser diode by referencing an inbuilt methane cell. This eliminates the need for expensive and time consuming calibration or the re-filling and transportation of hydrogen bottles associated with traditional FID based instruments.

The use of natural gas, of which methane is the principal component, for both industrial and domestic installations is increasing worldwide, and Crowcon foresees applications in leak survey, transmission integrity, plant and facilities management, agriculture and waste management, as well as process engineering applications such as coke and steel production. Each of these areas have situations where access may be difficult, combined with the need to put personnel protection at the top of the agenda. Opportunities for the LaserMethane® mini are substantial – put simply, it allows users to reliably detect methane at a safe distance.

For further information, news releases and sponsorship opportunities please email the editor - Nigel Lloyd.

The terms of the agreement include a significant investment by Shell in technology development with Iogen Energy Corporation, a jointly owned development company dedicated to advancing cellulosic ethanol. The arrangement will also see Shell increasing its shareholding in Iogen Energy Corporation from 26.3% to 50%. Shell first took an equity stake in 2002.

The collaboration with Iogen is a key part of Shell’s strategic investment and development programme in biofuels, particularly in 'next generation' biofuels using non-food feedstocks. The fuel is made from raw materials such as wheat straw and promises to reduce CO2 production by up to 90% compared to conventional gasoline.

Iogen’s first demonstration commercial plant opened in Ottawa in 2004. Shell is considering investing in a full-scale commercial cellulosic ethanol plant and is contributing to Iogen’s detailed feasibility and design assessment work.

Commenting on Shell’s increased investment, Dr. Graeme Sweeney, Shell Executive Vice President Future Fuels and C02 said “This is a strong statement that Shell is committed to accelerating the development of cellulosic ethanol in collaboration with Iogen. We have come a long way together already on this particular technology pathway for sustainable biofuel and we will be working ever closer to meet the technical and commercial challenges facing larger scale production.”

“We are excited to see this expanded partnership”, said Brian Foody, Chief Executive Officer of Iogen Corporation. “This transaction sets the stage for successful large scale cellulosic ethanol production.”

Construction is expected to span 42 months with delivery in the 4th quarter of 2011 at an anticipated cost of approximately $700 million, including owner furnished equipment, commissioning, project management and financing costs.

This rig will be a dynamically-positioned, four column semisubmersible capable of drilling wells to 8,500 meters in water depths up to 2,400 meters.

This entry by Scorpion into the deepwater segment of the offshore drilling business is the result of the continued execution of the Company’s original strategy. Scorpion’s semisubmersible contract is its second contract with Petrobras with the Offshore Defender having begun operations in Brazil in March. The addition of this deepwater semisubmersible to Scorpion’s fleet will supplement its ultra premium jackup strategy.

A contract to Nanuq, Inc, together with Alaska Frontier Constructors, Inc. (Nanuq/AFC), both of Anchorage, Alaska, is for construction and maintenance of nearly 50 miles of ice roads and an ice air strip needed to transport the drilling rig and associated materials, camps and personnel to the Point Thomson site. Barges to move the construction equipment to the Point Thomson site have been contracted. Additional contracts are planned for other key project activities. The construction activity advances the development of the Point Thomson hydrocarbon resource for the mutual benefit of Alaskans and the 27 Point Thomson Unit working interest owners.

Craig Haymes, Alaska production manager for ExxonMobil, said, "The Point Thomson working interest owners are proceeding with the drilling plan and the project while we seek to resolve the dispute with the State over the Point Thomson Unit. We are hopeful that we will resolve the differences to our mutual satisfaction. Even if we cannot do so quickly, we intend to carry out the drilling program as leaseholders. We have already hired Alaskans, commenced upgrades on a drill rig and ordered long-lead materials in preparation to commence drilling this winter. The plan will provide jobs for over 200 people this winter."

Point Thomson is remotely located 60 miles east of Prudhoe Bay. Use of ice roads is a well established Arctic practice that enables the transportation of heavy equipment and materials for development operations while protecting the North Slope environment.

The project includes an investment of approximately $1.3 billion, including a multi-year development and delineation drilling program that will commence in the 2008-09 winter season, to construct production facilities, pipelines, and support infrastructure.

Under the initial phase, approximately 200 million cubic feet per day of Point Thomson gas is expected to be produced. Approximately 10,000 barrels per day of liquid condensate that is separated from the gas is planned to be delivered for sale through new and existing oil pipelines. The remaining gas will be injected back into the Thomson Sand reservoir to maintain pressure for continued hydrocarbon recovery and for subsequent gas sales.

The recently-built helicopters to be supplied are of the Eurocopter EC225 type. This type is a further development of the SuperPuma helicopters operating from Hammerfest under the current contract.

The contract will cover StatoilHydro’s and Eni’s need for helicopter services for the companies’ overall activities in the Barents Sea.

”Through this helicopter contract we have secured resources for future operations in the Barents Sea and we have reached a good and flexible solution which involves the cooperation with Eni,” says Kjell Kristoffersen, head of operations and maintenance procurements in StatoilHydro.

The helicopters will be operating under harsh conditions and StatoilHydro has given safety and quality top priority by setting requirements for new helicopter technology.

”We will apply the latest available technology in helicopter safety through this contract for new helicopters of the EC225 type for SAR and transport services in the Barents Sea,” says Trude J Haugland, head of StatoilHydro’s air transport unit.

The contract has a duration of six years and will enter into force in June 2009, with an option to extend the contract by three years.

"The Ursa/Princess Waterflood project represents a significant investment by Shell and the other interest owners in one of the most prolific areas in the Gulf of Mexico -- the Ursa-Mars basin. Ursa-Princess has produced nearly 400 million barrels of oil equivalent to date and we believe potential exists for continued development of material oil and natural gas within this basin," said Russ Ford, Vice President Technical, Shell Americas. The Ursa/Princess Waterflood is one of the largest construction projects on an existing platform in the Gulf of Mexico. This presented challenges of very high activity levels and simultaneous construction, commissioning, maintenance and well servicing activities, while performing production operations on a large facility located 100 miles offshore. The relentless focus on hazard management and emphasis on reducing risk exposure resulted in strong safety performance over the entire project.

The contract is a framework agreement with call-off services in support of a major development programme in offshore west Africa. Subsea 7 has signed the first call-off contract under the frame agreement with an estimated value of $460m.

The services will primarily be performed using Subsea 7's new build flexible pipelay and construction vessel, the Seven Seas.

The contract entails the provision of engineering, procurement, construction, onshore commissioning, load-out and seafastening services for the HBD jacket, piles, topsides, flare and three connecting bridges, which has a total weight of about 16,500 tons, for the Halfdan Phase IV Development Project.

Facilities on the platform topsides will include processing, power generation and utilities. Construction is expected to commence in November 2008 with onshore completion scheduled 1st June 2010.

Mr Chew Sang Mon, SMOE’s General Manager for Commercial and Business Development said “This is the third major contract awarded by Maersk Olie og Gas for operations in the North Sea and the biggest single contract secured by SMOE to-date. In 1998, we had successfully completed two Wellhead Platforms for Maersk Oil Qatar for their Al Shaheen Field. This repeat order is a testament of Maersk Olie og Gas’ confidence in our turnkey capabilities and proven expertise in constructing offshore platforms and ability to meet stringent requirements for the North Sea.”

The drilling contract will have a fixed term of six years with start-up within December 31, 2012. Revenues which could be generated over the six year period are approximately USD 975 million, including a bonus arrangement and mobilization fee.

The "Sevan Brasil" will be designed to include the most advanced drilling capabilities in the industry, based on Sevan's own patented technology. The "Sevan Brasil" will have a variable deckload of more than 15,000 metric tons and a high storage capacity of bulk materials and drilling fluids, reducing the need for re-supply compared to semi-submersibles. The secluded moonpool area reduces the environmental impact of potential oil spills.

- This drilling contract is a confirmation of the long-term relationship between Petrobras and Sevan, and is in line with our strategy of expanding our drilling activities, especially in deepwater and demanding areas. We see the forthcoming high activity level in Brasil as a great potential for the Sevan technology. We will continue to expand our presence in the area, says Jan Erik Tveteraas, CEO of Sevan Marine ASA.

Technip’s operating center in Aberdeen, Scotland, and Genesis Engineering Consultancy, the Group’s consultancy and engineering company, will execute these services, which could include, conceptual engineering, project management, procurement, construction, installation, provision of diving support, trenching support and umbilical installation vessels, inspection, repair and maintenance. This is the first time Oilexco has implemented a subsea services frame agreement. This will guarantee availability of assets for Oilexco when required, enabling fast track project delivery.

The first project undertaken as part of the frame agreement will be the Shelley field development, located in the central North Sea. For this project, Technip will execute the engineering, installation and commissioning of pipelines, a control umbilical and jumpers, flexible risers, a subsea manifold and attendant flowline. This award marks a new step in the collaboration between Technip and Oilexco, for whom Technip undertook its first North Sea development, Brenda / Nicol, in 2006.

The tendency to build larger, wider vessels heralds a new challenge for the suppliers of marine evacuation systems. Not only must they cope with increasing numbers of passengers, but they must also be flexible enough to cope with increased vessel tilt and list. With today's post-Panmax breadth vessels, the variation in height in trim and list conditions in a distress situation can be enormous. Only an extremely flexible evacuation system can cope with such extremes. VIKING has designed and manufactured a new evacuation system that solves the challenge of evacuating passengers from wide vessels. The new dual chute system, the VEDC, copes with enormous variations in evacuation height and has one of the largest capacities available.

To meet all the requirements for trim and list, and for evacuation capacity, VIKING designed and built an entirely new dual evacuation chute system, the VEDC. VIKING's revolutionary elasticity system for the dual chute enables it to cope with extreme differences in evacuation heights, and is the most flexible chute system to date. It can safely evacuate passengers from evacuation heights as high as 16.8 metres and as low as 8.9 metres. The flexibility design is patent pending. Two chutes, side by side, evacuate passengers simultaneously, greatly increasing the number of people evacuated within 30 minutes. The VEDC dual chute system has an SOLAS approved capacity of 559 people per system, and evacuees are transferred dry-shod from the deck to 150 person liferafts. A unique element of the VEDC system is the float free function. Unlike other high capacity systems, the VEDC is not stored away in a large box that contains all elements. The liferafts can be released independently from the system and used separately if necessary.

The drillship is one of three Pride ultra-deepwater units under construction at the SHI shipyard. All three units have now been awarded contracts with durations of at least five years. The five-year contract is expected to commence during the fourth quarter of 2010, following the completion of shipyard construction, mobilization of the rig to an initial operating location and customer acceptance testing. Revenues that could be generated over the five-year contract term, excluding revenues for the reimbursement of costs associated with the mobilization of the rig, are approximately $984 million. The contract also provides for a cost escalation provision effective from April 30, 2008 through the five-year contract term.

Louis A. Raspino, President and Chief Executive Officer of Pride International, Inc., stated, "With this five-year contract award, Pride has further expanded its service to BP to now include two advanced-capability, ultra-deepwater drillships currently under construction and expected to begin operations in the U.S. Gulf of Mexico during 2010, the management of drilling activities on three deepwater production facilities in the U.S. Gulf of Mexico and deepwater drilling operations in the Eastern Mediterranean. This contract award allows us to further build a greater presence in the ultra-deepwater U.S. Gulf of Mexico, a strategically important and technically challenging region."

“Our innovative products and services for the oil drilling industry have already set us apart, but winning the Queen’s Award for International Trade is an independent endorsement of what the company has achieved,” said Tony Cutmore, Managing Director of Centek. “This is recognition of Centek as a top performer at the highest level of business professionalism, both here and abroad, and I am exceptionally proud of all our people.”

Centek manufactures casing centralisers, which are used in oil and gas drilling to position pipes down the drilled hole prior to cementation. The company was founded in 2001, and in the three years from 2004 its export sales have more than doubled, with 77 per cent of its business coming from outside the UK. Centek sells its products both direct and through distributors, and it has collaborative agreements with one of the World’s largest service and supply companies in the oil industry.

Centek emphasises product quality and customer support, and 80 per cent of its sales in the company year ending 31st October 2007 were repeat orders from existing customers. Centek has achieved ISO 9001-2000 and API SPEC 10 D – 0022 certification, both essential competencies in the oil industry.

The Queen's Awards for Enterprise are the UK's most prestigious awards for business performance, and are awarded for achievements in three categories: International Trade, Innovation and Sustainable Development. www.centekltd.co.uk

The value of the new contract is estimated to be approximately US$500 million (£250 million) over the five years. Under the contract, which is an extension of an existing eight-year contract, AMEC will provide engineering and construction management services to enhance and extend the life of all of BP's offshore installations in the Azeri sector of the Caspian Sea, which represents around 20 per cent of BP's global production.

The facilities include the Chirag, Central Azeri, West Azeri, East Azeri and Shah Deniz and the soon-to-be-developed Deep Water Guneshli assets, which are of strategic importance to Azerbaijan. Together, they currently produce over 1 million barrels of oil and 700 million standard cubic feet of gas per day.

AMEC's expertise in asset support and brownfield projects, excellent safety performance and a major presence in Baku, where it has developed a sustainable regional business, were important factors in AMEC winning the contract renewal.

"This is an important long-term asset support contract that reinforces our international growth strategy and our relationship with BP,' said Neil Bruce, Chief Operating Officer, AMEC's Natural Resources business. 'We have developed and continue to develop a strong position in the Caspian and surrounding region, where we have strong business relationships and a good understanding of local issues." Richard Rippon-Swaine, Azerbaijan Country Manager, AMEC's Natural Resources business added: "This latest contract underlines our excellent position in Azerbaijan. Since setting up in Baku 10 years ago, we have built a business that employs local people and delivered several successful major projects that have helped Azerbaijan's national oil industry to grow."

The new boat is scheduled for delivery from the shipyard in December 2009, but will likely go out on the spot market for a few months before starting its contract with StatoilHydro during the first quarter 2010.

“We are very pleased that many ship owners are following up with StatoilHydro’s emphasis on increasing safety for onboard crews by emphasising new technology,” says Morten Meinich, StatoilHydro marine operations head.

“The ship has state-of-the-art technology that enhances safety on deck during anchor-handling operations, including cargo rail manipulators which reduce manual work. The vessel also has hybrid engine solutions and catalytic converters that reduce nitrous oxide (NOx) and CO2 emissions. It has many uses, including anchor handling in deep waters, ROV operations and supply duties,” comments Meinich.

The contract is valued at between GBP 20 and 30 Million annually and will create around 100 new jobs. The award to one of the Aberdeen businesses of the global engineering and construction group comes in the wake of Fairfield's purchase of the Dunlin field cluster from Shell in December 2007.

Aker Solutions will undertake a number of initial studies on the installation, followed by an aggressive programme of modifications, including onshore engineering work, procurement and offshore construction. In delivering the contract Aker Solutions will be working very closely with Amec as the Dunlin platform duty holder.

The Dunlin oilfield is situated 195 km north-east of Lerwick, with first production in August 1978 from the Dunlin Alpha platform.

Rod Buchan, managing director for Aker Solutions maintenance, modification and operation business in Aberdeen said: "Fairfield Energy is a new client for us and is taking over its first North Sea asset. Our success in winning this work is very much aligned with our key strategic goals, one of which is to develop relationships with independent operators and new entrants to the UKCS. This award underlines our position as a leading modifications company in the North Sea and as the preferred partner of independent operators.

"Fairfield is a new entrant with ambitions to become a key North Sea operator, and we look forward to supporting their plans to achieve significant growth over the coming years and to delivering significantly increased value from the Dunlin asset."

This contract itself involves the abandonment of 2 platforms with associated wells and the removal of pipelines and subsea tie-ins. In addition to this, Proserv A&D have also been appointed in their project management and contracting capacity to ensure this project is managed safely, time efficiently and within budget. Huey Kliebert Vice President of Abandonment Services states “Proserv’s extensive abandonment and contracting services’ expertise and experience, positions Proserv A&D as a leader in the Gulf of Mexico. Our decommissioning, contracting, engineering and abandonment services are highly recognised globally as being able to deliver full decommissioning packages.”

These projects are due to take place concurrently in both the Ship Shoal and High Island blocks, where water depths are 37 and 194 feet respectively. Proserv A&D will provide total marine management of this project. This includes simultaneously mobilising both the appropriate lift boats, well abandonment personnel and the required equipment necessary to conduct the well abandonment and structural removals in both locations. Upon completion of these operations, Proserv will then synchronise the employment of a 1300 ton Derrick Barge, a diving crew and a dive support vessel in order to remove the platform, and abandon the pipeline and associated subsea tie-in.

The three-year contract calls for the provision of directional drilling, logging-while-drilling, cementing, logging and perforating, coiled tubing and stimulation services for 93 wells offshore Northeast Saudi Arabia. The offshore component of this project will utilize 10 jack-up rigs. The Manifa project is a key part of Saudi Aramco's plan to increase its overall production capacity.

Ahmed Lotfy, Halliburton's Eastern Hemisphere president, said: "To be selected by Saudi Aramco for yet another project of this magnitude demonstrates our client's continued confidence in our ability to successfully execute such complex and challenging operations. This contract award validates our commitment to expand customer relations with national oil companies and grow Halliburton's international business."

"Halliburton has worked with Saudi Aramco for nearly 70 years and has maintained an impressive track record of safely and successfully delivering mega-projects," added Gasser Badrashini, vice president of Halliburton's Saudi Arabia and Bahrain operations. "Following on from the success of our work on the Khurais mega-project, which is currently ahead of schedule, the award of the Manifa project reflects our solid performance and leading technologies."

"We are extremely pleased to be awarded these four contracts with major clients. This proves our capability to deliver our well proven process systems in a booming market," says Per Harald Kongelf, President for Aker Solutions' process systems business.

Two of the contracts have been signed with Mitsui Ocean Development & Engineering Co., Ltd (MODEC) for delivery of process modules to an FPSO. It is an EPC contract of the Aker Solutions Sulphate Removal Unit (SRU) and a Mono Ethylene Glycol (MEG) reclamation unit. These contracts are a breakthrough for our MEG technology in the FPSO market and they also strengthen the relationship between MODEC and Aker Solutions. Deliveries are scheduled to first half of 2009.

Aker Solutions has also signed a contract with Woodside for delivery of MEG reclamation system to Woodsides Pluto project. Pluto is an offshore gas field in North-Western Australia with an onshore Liquified Natural Gas (LNG) plant. The key proprietary equipment will be delivered in autumn 2008 with a gas production start scheduled to begin in the first quarter of 2010.

In addition, Aker Solutions will deliver crude oil dehydration system to OAO Globalstroy, a leading Russian construction company. Globalstroy is working under an EPC contract with the largest Russian crude producer, Lukoil. This will be the third contract signed with Lukoil to date and the most significant. As a specialist in heavy oil processing, Aker Solutions regards Russia and Kazakhstan strategic markets for the provision of our equipment and services. The company continues to pursue numerous other prospects with key customers in these markets.

The work will be undertaken by the Aker Solutions subsidiary, Aker Process Systems. These contracts were booked as order intake in first quarter 2008.

Under the agreement, FMC Technologies will manufacture and provide subsea production systems, engineering and life-of-field services for various offshore projects that LLOG is developing throughout the Gulf of Mexico, including MC72, Green Canyon 448 and Mississippi Canyon 503.

“We have enjoyed serving as LLOG’s preferred provider for the last several years,” said John Gremp, executive vice president of energy systems at FMC Technologies. “The signing of today’s alliance agreement comes only weeks after LLOG announced they had identified three new deepwater discoveries in the Gulf of Mexico. We’re excited about formalizing our alliance and welcome the opportunity to assist LLOG in developing their discoveries in the Gulf.”

For further information please visit - http://www.fmctechnologies.com/

Based on the data gathered in the Bo-3X well, studies will now be initiated to determine if the encountered hydrocarbons are commercial and if a possible development can be integrated with the ongoing development of the Valdemar - Bo Field.

Senior Vice President Anders Würtzen says: "We welcome the encountered hydrocarbons in the Bo-3X well and hope to have the commerciality confirmed. Drilling of the well was based on application of high-resolution 3D seismic data and innovative interpretation techniques.”

“Today’s announcement helps further solidify Enbridge as a leader in the development of energy delivery infrastructure in North America,” said Patrick D. Daniel, President and Chief Executive Officer, Enbridge Inc. “The Line 4 Extension complements Enbridge’s major expansion projects to enhance market access for Western Canadian crude oil production. Together with our Alberta Clipper Expansion and Southern Access Projects, Line 4 is a key component in expanding our mainline system capacity, strengthening the connection between secure, reliable energy from the Canadian oilsands and U.S. refining markets.”

Approval of the Line 4 Extension follows the recent NEB approvals of Enbridge’s Alberta Clipper Expansion and Southern Lights projects. With 1,607 kilometres (1,000 miles) of new pipeline construction, Alberta Clipper is the largest expansion project in Enbridge's history and is designed to move crude oil from a secure, stable North American source to U.S. Midwest markets.

Roxar Fieldwatch is a specialized Windows-based field monitoring system enabling E&P operators to ‘watch their fields’ remotely, and Roxar Fieldmanager is a comprehensive production data management system, allowing them to manage and interpret the field’s data. Both solutions are built on Roxar’s data acquisition technology, DACQUS®. The rapid retrieval and display capabilities of both applications will also give the user the ability to quickly visualize the data and identify trends, patterns or areas of interest for further analysis. The result will be increased information and reduced uncertainty when making crucial production optimization and reservoir management decisions. Said Roxar CEO, Gunnar Hviding: “E&P companies today require a complete picture of their reservoir, but are all too often overwhelmed by raw data with a single oil or gas field generating up to one terabyte of data per day . Whether it is temperature, pressure or flow rates, Roxar Fieldmanager and Fieldwatch are playing a crucial role in transforming this raw data into valuable decision-making information and providing a complete solution from field instrument through to desktop.” “With today’s E&P operator demanding an integrated, reservoir monitoring and asset management system, where the economic impact and risk of reservoir management decisions can be fully assessed, the timing of Roxar Fieldmanager and Fieldwatch’s market introduction could not have been better.”

The agreement covers a Contract Area of approximately 184,300 acres representing 75 percent of the license. ExxonMobil will have a 67 percent interest in the Contract Area and is the operator. TXM retains 33 percent of the Contract Area and 100 percent of the remaining license outside the Contract Area.

Under the terms of the agreement, ExxonMobil will conduct an initial work program to test existing wellbores and/or drill additional wells if needed to evaluate commercial production of unconventional gas and liquid hydrocarbons. ExxonMobil will invest $75 million in this initial phase, scheduled to begin this year.

After the initial work program, the agreement includes options for ExxonMobil to elect to follow with appraisal and development programs.

“ExxonMobil is pleased to add the Mako Trough in Hungary to our global portfolio of resource opportunities,” said Elwyn Griffiths, vice president, business development, ExxonMobil Exploration Company. “Effective pursuit and capture of a wide variety of opportunity types underpins ExxonMobil’s ability to deliver reliable, affordable energy to satisfy the world’s long-term and growing energy demand.”

The scope of work for this contract includes the fabrication and loadout of the 22,000MT jacket (including buoyancy tanks), 18,900MT of piles and the bridge link (approximately 100m long) to the North Rankin A Platform. Contracts of this nature are typically valued in excess of US$100 million.

“Completing the NRB substructure will be a major milestone for our Batam Island, Indonesia facility as this will be the largest jacket ever built in the Southeast Asia region,” said Scott V. Cummins, Vice President and General Manager, Asia Pacific “This award confirms our strong working relationship with Woodside. Their decision to award us this project underscores Woodside’s confidence in our ability to deliver large structural projects on time.”

The North Rankin Redevelopment Project will provide additional compression to unlock low pressure reserves from the North Rankin and Perseus gas and condensate fields off Karratha, Western Australia.

The NRB project, once completed will ensure continued gas supplies to the North West Shelf Venture’s liquefied natural gas facilities. Construction work will be performed at J. Ray’s facility on Batam Island, and is expected to begin in the fourth quarter of 2008. At the peak of construction, 1,300 people are expected to work on the project.

”The development of compact seabed separation plants is key to success in deep waters, such as in the Gulf of Mexico and off Brazil,” says the activity leader of the CompactSep JIP project, Olav Kristiansen, at StatoilHydro’s research and development centre in Trondheim.

Seabed processing allows tasks such as separation, pumping and compression to be performed on the seabed rather than on the platforms. The project aims to develop a plant that will work in water depths down to 2500–3000 metres. Traditional separators are too heavy to be lifted down into such deep waters. They will also get a bulky wall thickness due to great external pressure. Reducing the weight and dimensions is crucial.

”We will build a three-metre high, six-metre long demonstration rig for extensive laboratory and function tests, using model fluids and real fluids, both under low and high pressure,” Kristiansen says.

The first tests will take place in StatoilHydro’s research and development laboratory in Trondheim. The entire separation system will then be tested in a high-pressure rig at the SINTEF research foundation, where larger high-pressure facilities exist. Finally, StatoilHydro’s research and development centre in Porsgrunn will take over. Full-scale testing of the plant, using real gas and oil types, will be performed here. Parts of the system will at the same time be tested with well stream on the Gullfaks C platform in the North Sea.

The research project is managed and performed by StatoilHydro as a joint industry project (JIP), with the three companies as equal partners. The contract is based on the existing technology cooperation agreement recently signed with Petrobras and Chevron. The project, with a cost limit of NOK 54 million, will run until 2011.

In the Ebla project, Petro-Canada is operator with a 100% interest in a production sharing contract to develop and produce natural gas from the Ash Shaer and Cherrife fields. First gas is scheduled for delivery in 2010.

Subsequent to the contract award, Petrofac’s Energy Developments division has agreed in principle with Petro-Canada to purchase a 10% interest in the Ebla production sharing contract, subject to the approval of the Syrian government.

The Ebla gas treatment plant will be located in the Ash Shaer field between Homs and Palmyra. The initial contract, which will last just over two years, will include all associated facilities and infrastructure, including engineering, procurement and construction, commissioning and start-up assistance of the gas treatment plant, pipelines, gas gathering station flow lines and well sites. The Ebla plant will be designed to produce 88 million standard cubic feet of sales gas per day, 150 tonnes of liquid petroleum gas per day and handle the associated condensate; sales gas and condensate will be fed into the Syrian pipeline grid and LPG will be transported via tankers.

Commenting on the award, Maroun Semaan, Chief Executive, Petrofac Engineering & Construction, said: “This is another significant award in Syria for Petrofac which, taken together with the Jihar gas plant award, provides us with almost US$1 billion of work in a country where we have successfully worked on a number of projects. It confirms our position as a leading and successful contractor in the gas processing sector.”

Ayman Asfari, Petrofac’s Group Chief Executive added: “We are delighted to have been offered the opportunity to partner with Petro-Canada and the Syrian Government and we look forward to demonstrating the benefits of our integrated service offering on this exciting development.”

Peter Kallos, Petro-Canada’s Executive Vice-President, International & Offshore, commented: “We are very pleased to have Petrofac’s involvement on this project, which offers significant potential to Petro-Canada and our partners but has a demanding schedule for delivery of first gas. This agreement will be a major factor in successful execution of the project.”

The project – worth around £1.5 million – saw Opus install a fully integrated, skid-mounted CFU, including Mare’s Tails, to treat two separate streams onboard the Hess-operated Triton FPSO (Floating Production Storage and Offloading) vessel, located in the UK sector of the North Sea. The project – which aims to reduce the concentration of oil in produced water from Triton – has been hailed a great success.

Opus Maxim’s compact flotation technology has assisted Triton in improving the quality of waste water, which occurs naturally in oil and gas reservoirs, enabling Hess to meet rigorous environmental standards. The Opus CFU treatment system achieved up to a 94% removal efficiency, reducing oil-in-water content on the outlet down to 10ppm (parts per million).

Nigel Weir, managing director of Opus Maxim, says he is extremely pleased with the results from the Triton commissioning, particularly as they were achieved in challenging conditions.

He said: “The robustness of the Opus system was really tested under demanding offshore conditions. Start-up and process control is excellent and the operation is very stable - we experienced wide transient inlet conditions which included varying flow rates, oil and solids inlet loading and motion. “The CFU work on Triton was undertaken during heavy seas – with Storm Force 10 gales hitting the local area at the time of commissioning – but the team, together with the technology, successfully achieved the operational and contractual objectives.

“The rocking motion of a ship can have a detrimental effect on oil/water separation and Opus’ CFU technology has been developed to withstand these conditions and so is ideal for FPSO applications.”

Mr Weir added that he believes the successful completion of the Triton project heralds the start of an exciting period for the company. He said: “We are thrilled this major project has been delivered so successfully, as our compact flotation technology has undergone an intensive and meticulous research and development programme.

“We are already working on a number of similar projects on platforms in the North Sea and with ongoing research and development to develop the technology further still, I am confident our CFU technology will play a major role in the continued growth and future success of Opus in years to come.” For further information about Opus Maxim Ltd please call 01483 414 037 or visit www.opusmaxim.com

The contract is expected to commence during July 2008 in direct continuation of the rig's current contract commitment, also with the Total subsidiary offshore Angola. Revenues that could be generated over the five-year contract, inclusive of a performance bonus opportunity of up to five percent of the contractual operating dayrate, total approximately $862 million, excluding revenues for mobilization, demobilization and client reimbursables.

The Pride Angola is one of eight deepwater drillships and semisubmersibles in Pride International's fleet, six of which are dynamically positioned units. The rig, which is designed for operating in water depths of up to 10,000 feet, but currently equipped for drilling operations in 6,000 feet of water, has been under contract to Total's Angola subsidiary since it entered service in 2000. The rig has achieved an operating and safety performance that ranks among the industry's best, including less than 1.5% mechanical downtime since January 2001 and no lost-time incidents since May 2002. The impressive operating performance has resulted in the rig realizing greater than 95% of its bonus opportunity since commencing operations.

West Sirius was delivered within 30 days from original delivery schedule, while West Phoenix, due to customer initiated modifications, was delivered approximately three months after original contract date. Both drilling rigs were delivered with only minor deviation to the budget which was agreed when the rigs were fixed to the charterer.

The units will proceed for mobilization, and estimated time of arrival for West Phoenix in the North Sea is in the beginning of the third quarter 2008, and estimated time of arrival for West Sirius in the Gulf of Mexico at the end of the second quarter 2008. Both drilling units have secured long-term contracts. West Phoenix has a three-year contract with Total Norge to utilize the unit in the North Atlantic region. West Sirius has a four-year assignment with Devon Energy Corporation to utilize the unit in the Gulf of Mexico.

West Phoenix and West Sirius are both sixth generation, deepwater, state of the art drilling units and some of the most advanced drilling rigs ever built, based on proven designs and performance.

The drilling units belong to a high specification, new generation drilling units, focusing on a broader spectre of capabilities, a larger operating area, a high load carrying capacity, decreased dependence on frequent supplies, efficiency and improved safety and working environment as well as a special environmental focus, minimizing the exposure to the environment. The drilling units are designed with a dynamic positioning system and a water depth capability up to 3,000 meters. In addition, West Phoenix is designed with a dual derrick and is constructed for winter operations in northern and arctic areas.

Commenting on the delivery, Chief Executive Officer in Seadrill Management AS, Kjell E Jacobsen said, "Seadrill has reached a highly important milestone with the delivery of the first two newbuild deepwater drilling units out of eight units to be delivered this year." Project costs for each of the two units are in line with what have been previously reported.

Upon commencement of the contracts, Seadrill will invoice their two customers approximately US$70 million in mobilization payments. Chairman John Fredriksen in Seadrill Limited says in a comment, "The completion of the two newbuilding projects confirms the Seadrill organization's ability to manage complex projects within time and cost and is a great achievement for our organization and the people involved. It also confirms that the Seadrill strategy to order newbuilding units with highly reputable yards like Jurong and Samsung is paying off.The combination of a favorable contracting price, good charter agreements and sound newbuilding execution with timely execution will yield significant return to our shareholders."

The contract has been awarded by Elf Petroleum Nigeria Limited (Total), as the Operator of Oil Mining License (OML) 1381 where the Usan field is located. It encompasses the engineering, procurement, construction, installation, pre-commissioning, assistance to commissioning and start-up of the subsea umbilicals (72 km), flowlines (61 km) and risers connecting the 42 subsea wells to the FPSO, along with the oil loading terminal, consisting of an offloading buoy and two offloading lines, and part of the FPSO anchoring system.

Fabrication will be carried out locally in Nigeria, mainly in Saipem’s Rumuolumeni yard. The offshore installation will be carried out by the highly specialised vessels Saipem FDS and Saipem 3000, in water depths ranging from 730 to 850 metres, between the fourth quarter of 2010 and the fourth quarter of 2011.

Prysmian Cables & Systems, a world leading company in the Power and Telecommunication Cables and Systems industry, has been awarded a US$ 18m contract by Brazilian company Petrobras (Petróleo Brasileiro SA) for 35km of static and dynamic Steel Tube Umbilicals to be installed in a number of fields in the Santos, Campos and Espirito Santo Basins, located offshore to the Brazilian coastline. Umbilicals are multifunctional tubing systems which enable sub sea wellheads and manifolds to be connected to platforms or FPSO’s (Floating Production Storage and Offloading). Prysmian designs and produces these products and solutions at its industrial facility in Vila Velha, Brazil.

This contract represents a step forward in reinforcing Prysmian’s positioning in the high value-added market segments of industrial cables for the Oil, Gas & Petrochemical industry, and furthermore consolidates the relationship with its key client Petrobras.

These Umbilicals will form part of the Brazilian State sponsored “Plangas” initiative whereby the Brazilian state controlled company, Petrobras, intends to significantly increase its national daily gas production. The first step of this major project consists of the acceleration and expansion of gas fields already in operational or developmental phases and corresponds to 40% of the additional gas volume forecasted for 2008. The project requires electro-hydraulic umbilicals, in eight different configurations to be installed in nine fields along the Brazilian coast.

The Umbilicals will consist of 9x10,000 psi hydraulic lines, 3x10,000 psi injection lines and four pairs of electrical control cables. This contract will also mark one of the first dynamic production Super Duplex Stainless Steel Tube Umbilicals to be installed by Petrobras in Brazil, which historically has used Thermoplastic hoses. Ranging in water depths of up to 2000m, the umbilicals will be delivered on a fast track basis during 2008, following full qualification testing with the first delivery in mid 2008.

Personnel in Johor perform procurement and customer-service activities, as well as engineering, machining and product assembly. Approximately 100 employees work in the facility today and headcount is expected to exceed 250 by year-end. The Johor facility primarily will supply the company's completion equipment and cementing tools to customers in the Asia Pacific, Middle East, Africa and Europe Eurasia regions.

"We are excited to launch today a greater offering of our products and equipment to our Eastern Hemisphere customers," said David King, president of Halliburton's Completion and Production division. "The addition of the Johor facility is another step in our company's strategic plan to concentrate more of our investments and supply chain resources to our key growth areas."

Len Cooper, Halliburton's senior vice president, Supply Chain and Management Systems, added: "This facility creates a more responsive organization for our international customers while building regional supply networks that support local economies."

"Johor is the economic development hub of Malaysia," said Rao Abdullah, Halliburton's country lead for Central Asia. "Our talented employees here add a strong link in our global supply chain and it is very exciting to network Malaysia into Halliburton's expanding production facilities."

The Shtokman gas field is located in the Barents Sea and is one of the world's largest gas condensate deposits with reserves of approximately 3,800 billion m3 of gas and 37 million tons of hydrocarbon condensate. The onshore facilites for Shtokman Phase 1 will be located at a site adjacent to Teriberka, 120 km east of Murmansk. Phase 1 includes an offshore gas pipeline terminal, a gas treatment plant, a liquefied natural gas (LNG) train with a capacity of 7.5 million tons per year and an export plant for the Russian and European markets.

Technip's operating centers in Paris, France and Saint Petersburg, Russia, will execute the contract. The FEED, which is scheduled to be completed by mid-2009, will form the technical basis for the detailed design, procurement and construction contracts that will be awarded later on. In addition to the FEED contract, Technip has been awarded two additional contracts, one to establish a set of project standards and the second to assist Shtokman with the definition of site preparation works.

For the project, currently planned to be executed over several phases, JPK is providing Front End Engineering Design (FEED) and management of all activities associated with engineering the pipeline. Contracted to provide support throughout all phases of the project, JPK entered phase 1 of the development of the Shtokman natural gas field development in January.

Gerwyn Williams, Managing Director, J P Kenny said, "We are very pleased to have won this contract, which adds to our portfolio of cold region engineering projects. The project comprises a 600km 44” subsea pipeline from the Shtokman field running south to Murmansk. We will be executing the work in our London and Norwegian offices, supported by a Russian contractor, and we'll also be strengthening our presence in Russia by establishing a JPK office in St Petersburg, managed by Russian engineers.”

He added, “As the industry moves into deeper water and more remote environments, we can apply our subsea engineering capabilities to help our clients commercialise the breakthrough technologies needed to economically develop these new discoveries.”

For the technically challenging Shtokman project, which lies in arctic waters beyond the reach of divers, JPK will be delivering its tried and tested solutions to deepwater pipeline installation and will also be responsible for managing an extensive range of interfaces in terms of procurement, planning and compliance with Russian regulations.

These reserve additions came from various sources including the Williston Basin acquisition, enhanced oil recovery operations in North Dakota and successful exploratory drilling in the Cinco Terry Field in Crockett County, Texas. The initial shallow exploratory well in the Newporte prospect (E-M Engh #33-4) located in Renville County, North Dakota has been plugged and abandoned. The well was drilled to a depth of approximately 5,100 feet to test the Madison group and was deemed to be non-commercial after logging, coring and formation testing. The shallow horizons imaged from the 3D seismic data and tested in the E-M Engh #33-4 were not the primary target in the Newporte prospect area. The results from the E-M Engh #33-4 do not diminish the prospect potential of the deeper horizons in the Newporte prospect area that include the Winnipegosis, Red River, Winnipeg and Deadwood formations. The first deep exploratory well on the Newporte prospect (Osterberg #10-3) will be drilled to an approximate depth of 10,000 feet to test the Deadwood sandstone. The Company expects to commence drilling operations during second half of April, 2008 subject to the approval by the State of North Dakota of a unit spacing exception permit and the availability of the contracted drilling rig.

The Company also anticipates spudding the E-M Overton 20-10 well in Renville County, North Dakota this week. The Overton 20-10 well is the second well to be drilled in the Kolbo prospect area and is approximately one mile northeast of the initial well that showed excellent reservoir quality rock with good oil shows. The Company in conjunction with Approach Resources has participated in the discovery of the Cinco Terry Field located in Crockett County, Texas. To date, the Company has participated in 22 successful wells out of 24 locations drilled. The field is currently producing approximately 140 barrels of oil equivalent per day net to the Company. Our plan currently provides for one to two rigs drilling in the field on a continuous basis. The Company has participated in 14 successful wells in our Gulf of Mexico partnership with Hall-Houston Exploration. The partnership is currently conducting drilling operations on Matagorda Island 594 # l well. Future plans provide for two development wells to be drilled in 2008. The partnership has 12 exploratory prospects currently in inventory.

Located onshore in Alaska, 40 kilometres Southwest of Prudhoe Bay, the blocks cover an area of approximately 2,000 square kilometres. The exploration campaign is under way with three wells planned for this drilling season (Winter 2007-2008), and additional exploration wells planned for next winter's season as well.

Total will work closely with the operator, to protect the Alaskan environment. A wide range of measures are implemented to preserve the soil, air, water and wildlife. This acquisition illustrates the Group's desire to pursue its growth strategy in exploration areas with high potential.

Corporate strategy continues to focus on the accumulation of proven and proven producing reserves allowing potential investors the leverage of the physical commodity for which its lease acreage controls. Further reserve studies and updated reports of existing paperwork are being compiled and will be available over the next couple of months.

Oil from the field will be produced by using the Mærsk Inspirer jackup rig, while Navion Saga will be used as a storage vessel for further transport.The gas will be sent to the Sleipner A platform for final processing and export.

Recoverable reserves are estimated at 78.6 million barrels of oil and 1.5 billion standard cubic metres of gas. Production is expected to reach plateau production of 50,000 barrels per day by the end of the first quarter of 2009.

StatoilHydro is operator of the field and has assigned the operations activities to Maersk. Maersk Inspirer is the world's largest jackup rig and the only one of its kind used for production purposes on the NCS.Mærsk Inspirer started drilling in the summer of 2007 and has also completed the processing plant during this period.It has been decided to develop the field with eight wells but another five wells are already being planned and matured.

Technip's operating center in Aberdeen (Scotland) will execute the contract.

It covers:

• project management
• assembly and installation of a production pipeline
• a gas lift pipeline
• a water injection pipeline and an oil export pipeline
• installation of a subsea structure
• eight flexible risers(1) and;
• two umbilicals(2), and;
• pre-commissioning
• tie-ins and testing.

Offshore installation is scheduled for the third quarter 2008 using two vessels from Technip's fleet, the Apache and the Wellservicer. The pipelines will be welded at the Group's spoolbase in Evanton, Scotland.

In the short time since our beginning we have concluded a technology share agreement with Petrowell Limited of Aberdeen, with whom we will initially share this facility. Additionally we have signed an agreement covering the design, manufacture, distribution, service and maintenance of a range of RFID operated wellbore clean up tools.

This multi million dollar deal, signed in January 2008, and with the industry's Houston based field leader is a major step in i³TEC's development. I felt it important that i³TEC demonstrates its commitment to supporting our clients; operator and service industry alike by headquartering part of our operations on their doorstep. RFID has the potential to change the way we view the remote operation of downhole tools, and Houston is and will be one of the hubs of excellence as this technology takes shape."

www.iiitec.com

The increase in oil production offset declines in gas production. As result, revenue increased 9% to $1.3 million. The Company continues to shift its production to take advantage of record high crude oil prices, with more than 77% of Spitfire's production now weighted to oil.

In the third quarter, the Company evaluated a portfolio of assets for acquisition. Spitfire continues to look for assets that offer a predictable production base with a mixture of exploration and development upside. As Spitfire works to identify potential acquisitions, the Company is prepared to add additional engineering, land and exploration talent required to facilitate growth. In the meantime, Spitfire's Saskatchewan production base continues to provide steady cash flow.

The contract is Hallin's largest to date and runs for the next two years with a subsidiary of the Singapore quoted Swiber Holdings Ltd (Swiber). The wholly-owned Swiber subsidiary, Kreuz Offshore Marine Pte (Kreuz). Ltd, will take the Hallin operated Sanko Angel, fitted with one of the Company's saturation diving systems, on a fixed and firm charter for two years. The contract, which starts immediately, will initially operate on projects offshore of Indonesia and Malaysia.

Additionally, a technical service agreement has been put in place, whereby Hallin will provide Kreuz with specialist subsea personnel and additional support equipment, which could increase the size of the Company's project scope significantly.

The 76 metre Sanko Angel is a versatile, multi-purpose, offshore subsea operations and support vessel. It can accommodate up to 128 personnel onboard and is fitted with 50T Subsea crane and helicopter-deck. It will be operating in DP2 (dynamic positioning class 2) mode during the construction and subsea projects.

He holds a bachelor's degree in mechanical engineering from the University of Minnesota and a master's degree in business administration from the University of Houston.

Mr. Kruger began his career with Exxon Company U.S.A. in 1981 in Houston, Texas, and in subsequent years he held various engineering, business planning and management assignments. In 1994, Mr. Kruger was appointed production advisor for Exxon Corporation in Irving, Texas, and in 1996 he returned to Houston to become technical manager for Exxon Ventures with responsibility for Russia and the Caspian Sea. In 1999, Mr. Kruger was appointed vice president of ExxonMobil Development Company with responsibility for deepwater oil and gas developments offshore Africa. In 2001, Mr. Kruger transferred to Kuala Lumpur to become chairman and CEO of ExxonMobil Exploration and Production Malaysia.

In 2003, Mr. Kruger returned to Houston to become vice president for Asia Pacific/Middle East, ExxonMobil Production Company and in 2005 became vice president for the United States, ExxonMobil Production Company. Mr. Kruger was appointed executive vice president of ExxonMobil Production Company in 2006.

Mr. Foster, 64, joined Exxon USA in 1965 as an engineer in the Production Department. During his career, he held a number of domestic and international management assignments. Prior to the ExxonMobil merger, these positions included planning manager and production division manager of Exxon USA, production manager responsible for the UK affiliate of Exxon Company International, vice president, production, of Exxon Company International, chairman and CEO of Esso Malaysia, senior vice president, upstream, of Exxon USA and president of Exxon Upstream Development Company.

Subsequent to the ExxonMobil merger, he was appointed president of the ExxonMobil Development Company in December 1999. He was appointed president of ExxonMobil Production Company in October 2004.

A native of Texas, Mr. Foster holds a bachelor's degree in mechanical engineering from Texas A&M University. Mr. Foster is a member of Texas A&M University Board of Regents, the Texas Board of Professional Engineers and the Society of Petroleum Engineers.

Bechtel, in cooperation with ConocoPhillips under the ConocoPhillips-Bechtel Global LNG Collaboration, has been involved in detailed engineering and procurement for the Angola LNG liquefaction train since early 2007. “The first LNG production is slated for early 2012,” says Bechtel Project Director José Ivo.

The plant, adjacent to the town of Soyo, Republic of Angola, will utilize ConocoPhillips' Optimized Cascade(SM) LNG process and will produce LNG; LPGs, such as propane and butane; condensate; and domestic pipeline gas. The Angola LNG project is an integrated gas utilization project encompassing offshore and onshore operations to monetize gas resources from blocks located offshore of Angola.

The project will reduce natural gas flaring and greenhouse gas emissions from offshore oil producing areas, facilitate continued offshore oil field development, and contribute to the development of a future natural gas-based industry within Angola. Bechtel's engineering, procurement, and construction contract covers the onshore portion of this project.

The two stakes owned through Shell Nigeria Exploration and Production Co. Ltd. are in deep water blocks OML-125 and OML-134, the latter formerly known as OPL-211. Agip, a unit of Eni, owns the remaining 50.2% in each block.

OML-125 currently produces 18,000 barrels a day of oil from the Abo field combined with near term production growth and high potential exploration acreage to complement Oando's existing upstream position. OML-134 although still in exploration phase, has already recorded significant discoveries.

The consideration payable is US$625.7m in cash which will be settled in two tranches. An immediate payment of 10% was paid on Friday, 22nd February whilst the balance will be paid on completion. The consideration and any adjustments will be funded from both internal cash resources and from external financing. Standard Chartered, Standard Bank, BNP Paribas and Merrill Lynch are providing financing to Oando for this transaction. Standard Chartered Bank acted as financial Advisors to the transaction.

Wale Tinubu, Group Chief Executive, Oando Plc said, “We are please to have emerged as the preferred bidder in this competitive international bid. This milestone underpins our preparedness and capability to develop a sizeable upstream portfolio.”

“We have been fortunate to be presented with the rare opportunity to acquire a balanced upstream portfolio in our home market in line with our stated principle to acquire proven, active and near term properties. Our ability to marshal substantial resources to win a bid of this magnitude further reinforces our status as sub-Saharan Africa's leading integrated energy group. We are proud of this development and the positive impact on Indigenous corporate Nigeria's profile in the global oil and gas community.”

The sale is subject to approval by the government and waiver of pre-emption rights by Agip.

Under the existing pooling agreement, Blackdog has a 60% working interest and Privco has a 40% working interest in the proposed wells. The final working interest terms are subject to negotiation. Privco has recently drilled a horizontal well immediately adjacent to the Whitebear property that has tested at approximately 150 barrels of light oil per day. The first joint well is anticipated to be drilled post spring breakup in May/June of 2008. Blackdog President David A.

Corcoran comments, “Southeast Saskatchewan has become a very hot area for horizontal drilling given the royalty holiday on up to the first 48,000 barrels of oil per well, the extremely long expected producing life of these wells which can be between 25-40 years, the high prices received for the valuable light oil produced, the easy year round access and the solid infrastructure that is already in place to handle the oil and water from these wells.

We look forward to drilling our first well this spring and pending success from this well additional wells later in the year.” Blackdog also announces that it has cased its farm-in oil well drilled in Pembina, Alberta in December, 2007 as a potential oil well. Testing continues in two zones of interest in the well. Blackdog has now earned a 12% working interest in two sections of land pertaining to the drilling of well. Forward Looking Statements – This press release contains statements about future events that are forward looking nature and, as a result, are subject to certain risks and uncertainties such as changes in plans or occurrence of unexpected events. Actual results may differ from the estimates provided by management.

www.blackdogresources.com

Under the two-year contract, the value of which has not been announced, MMC AMEC will provide project management, engineering and related services for an asset integrity and de-bottlenecking project on the Malampaya gas field in the Philippines and will cover both the field's integrated platform and onshore gas plant. The contract is part of the Malampaya Deep Water Gas to Power development, which is estimated will provide enough gas to generate 30 per cent of the country's electricity until 2022. AMEC has provided support services to Malampaya since 2000.

"We are delighted to continue to provide support to our long-standing customer Shell on this major development," said Tony Cruddas, President of Growth Regions for AMEC's Natural Resources business.

Mr Noorul Khairi, Chief Executive Officer of MMC AMEC, added: "This is the first major contract to be delivered through MMC AMEC, which was set up in September 2007, and is a key milestone in its successful establishment."

Headquartered in Malaysia's capital, Kuala Lumpur, MMC-AMEC specialises in large-scale integrated projects, including deepwater, as well as providing more traditional greenfield and brownfield engineering services for both upstream and downstream sectors of the global oil and gas market.

ExxonMobil submitted the plan to the Alaska Department of Natural Resources. It involves evaluation, delineation and development of Point Thomson reservoirs through a phased approach to fully develop the hydrocarbon resource for the mutual benefit of Alaskans and the unit working interest owners. Production is anticipated to start by year-end 2014.

The project includes an investment of approximately $1.3 billion to commence a multi-year development and delineation drilling program in the 2008-09 winter season and to construct production facilities, pipelines, and support infrastructure.

Under the initial phase, approximately 200 million cubic feet per day of Point Thomson gas is expected to be produced. Approximately 10,000 barrels per day of liquid condensate that is separated from the gas is planned to be delivered for sale through new and existing oil pipelines. The remaining gas will be injected back into the Thomson Sand reservoir to maintain pressure for continued hydrocarbon recovery and for subsequent gas sales.

In addition, engineering work will be completed to provide necessary information that will allow individual Point Thomson Unit owners to participate in an open season for a gas pipeline. Subsequent field development will be determined, which could include expanding the injection capacity, oil production, pursuing gas sales or a combination.

Craig Haymes, Alaska production manager for ExxonMobil, said, "We look forward to working with the State of Alaska to delineate and bring Point Thomson hydrocarbon resources into production. We have completed significant engineering and geoscience work over the past 18 months, focused on reservoir evaluation and development planning. The assessments indicate that a phased development is a prudent approach to maximize the benefits to the State of Alaska and the Point Thomson owners, especially since a gas pipeline is more than a decade away."

Since 1954, ExxonMobil has invested over $20 billion dollars to develop Alaska's petroleum resources. The company's current working interest share of oil production in the state is approximately 140,000 barrels per day.

In addition to ExxonMobil, the other major Point Thomson Unit owners include BP Exploration (Alaska) Inc., Chevron U.S.A. Inc. and ConocoPhillips Alaska Inc.

WellDynamics will install electronic Venturi flowmeters, electronic pressure/temperature gauges in wells with WellDynamics' SmartWell® completions, and additional electronic pressure/temperature gauges in wells where WellDynamics' flowmeters are installed. This frame agreement applies to all previous Hydro assets in the North Sea. WellDynamics was one of three vendors selected to provide services for the entire contract, estimated to be worth 1 billion NOK, including options, over an eight-year period beginning in Q1 2008.

“The three new frame agreements for downhole monitoring help in securing access to a broad range of measurement technologies for use in advanced wells to maintain productivity levels on the Norwegian Continental Shelf in years to come,” said Vidar Skjæveland, Head of Procurement Drilling and Well Services, StatoilHydro. “We believe that they provide an important means for increased recovery of both new and existing wells.”

Under terms of a separate frame agreement, WellDynamics will provide and implement SmartWell® technology in four wells in StatoilHydro's Gjøa field. The contract is estimated to be worth as much as 45 million NOK over six years, beginning in 2009.

StatoilHydro, established in October 2007 as a merger between Norwegian companies Statoil and Norsk Hydro, has a longstanding relationship with WellDynamics. “We are eager to join with StatoilHydro in the expansion of technologies in the North Sea,” said Derek Mathieson, president and CEO, WellDynamics. “Innovation is critical to improving ultimate recovery across the industry, and we look forward to helping StatoilHydro achieve its goals in these exciting new projects.”

WellDynamics' SmartWell® intelligent completion technology includes solutions for flow control, zonal isolation, permanent monitoring and downhole control, as well as digital infrastructure and fiber optic systems.

The Makassar Strait Explorers Consortium (MSEC) comprises Marathon International Petroleum Indonesia Ltd, Anadarko Popodi Ltd, ConocoPhillips (Kuma) Ltd, ENI Bukat Ltd, Statoil Indonesia Karama AS and Talisman (Sageri) Ltd.

The 689-day contract is expected to commence in the fourth quarter of 2009 following the completion of existing contractual commitments in Angola and mobilization to the Makassar Strait, a deepwater province receiving renewed interest as a result of recent leasing activity.

The estimated contract revenues which could be generated over the 689-day contract period are approximately $351 million. Estimated contract revenues represent the maximum amount of revenues that may be earned in the firm contract period, excluding revenues for mobilization and demobilization.

The GSF Explorer is one of 18 Ultra-Deepwater Floaters in the Transocean fleet. Constructed in 1972 and upgraded in 1998, the drillship is capable of working in water depths up to 7,800 feet.

For the three month quarter ended December 31, 2007, EnerJex delivered a 258% increase in quarter to quarter oil and gas revenues – from $418,590 for the three months ended September 30, 2007, to $1,498,202 for the quarter ended December 31, 2007.

In addition, there was a fifty-six-fold increase in the three month oil and gas revenues for the quarter ended December 31, 2007 – from $26,491 for the quarter ended December 31, 2006. For the nine month period ended December 31, 2007, EnerJex reported oil and gas revenues of $1,982,119, as compared to $76,314 for the same quarter in 2006.

The revenue increase for both the third quarter and the nine months ended December 31, 2007 reflects the aggressive implementation of EnerJex's business model, resulting in growth in crude oil production volumes from leases acquired and developed during these periods as well as increased commodity prices. EnerJex began acquiring oil leases in April 2007.

For the three and nine months ended December 31, 2007, net oil sales volumes were 16,854 and 25,674 barrels respectively, compared to zero barrels for those same periods in 2006. The average commodity price received by EnerJex was $88.89 per barrel of oil for the quarter ended, and $77.20 for the nine months ended, December 31, 2007.

Since April of 2007, EnerJex has closed four acquisitions, drilled 90 new wells (with a 98% success rate), and increased its pre-tax PV-10 (present value) of Proved Reserves by more than $30,900,000 or 1.2 million barrels of oil equivalent. EnerJex has also identified more than 400 additional drilling locations on its existing leases.

Based on production levels achieved during the end of the December 31, 2007 quarter, EnerJex became operationally cash-flow positive, on a non-GAAP basis. As a result, EnerJex will continue to pursue its drilling programs using internally generated funds and other capital alternatives.

EnerJex's CEO, Steve Cochennet, stated, “We are extremely pleased with the results of our efforts to-date. With a 98% drilling success rate and the identification of 400 additional drillable locations – plus quickly building to $30.9 million in PV-10 Proved Reserves as well as $17.2 million in Probable Reserves – we are confident that we have tremendous growth potential ahead of us. We look forward to seeing dramatic results in 2008 and beyond.”

"Aker Kvaerner is recognised for its development of innovative deepwater drilling technologies, satisfying the industry's requirements for efficiency, safety and operability. Acquisition of this technology and competence is a strong strategic lever for us going forward", says Mads Andersen, executive vice president in Aker Kvaerner.

First Interactive AS is a software company specialising in 3D visualisation and simulation for the oil & gas sector. First Interactive has headquartered in Stavanger, Norway, with a subsidiary in St. Petersburg, Russia. In 2007, First Interactive realised revenues in excess of NOK 25 million.

First Interactive and the Aker Kvaerner subsidiary Aker Kvaerner MH, are jointly developing applications for 3D visualisation and simulation of offshore drilling operations. A new generation drilling simulator, enabling realistic 3D visualisation and real-time scenario building, is already launched. The simulator will primarily be used for training of rig operators, but also enables significant reduction in commissioning of drilling rigs currently under construction. The two companies are currently developing solutions for real-time, 3D visualisation of drilling operations which will enable onshore support and control of offshore operations. First Interactive's technology and competence can also be applied to other parts of Aker Kvaerner's business such as marine installation, subsea and well services.

"A realistic, real-time visualisation of the drilling operations will enable rig operators to make better and faster decisions. The result is more efficient drilling, and increased rig uptime. In addition this tool enables us to offer superior training facilities for our clients as well as our own employees," says Roald Amundsen, President of Aker Kvaerner MH.

As the world's first self-propelled, 325-foot/100-meter nominal water depth-rated jack-up well intervention vessel, Remedial Offhore's ESV™ design provides a hybrid between a jack-up drilling rig and a marine vessel.

The new ESV concept offers tremendous versatility and operational functionality, ranging from an incorporated electric well workover package to a large open deck for offshore support functions.

Each vessel is uniquely outfitted to provide a stable work environment for deploying today's most advanced well intervention production enhancement technologies. ESV abilities include well workovers, sidetracking, well abandonment, facility upgrades, brownfield rejuvenation projects and small field developments, as well as providing complete services for well intervention.

Each ESV will employ four GE diesels -- one 8-cylinder V228 and three 16 cylinder engines. Two Remedial Offshore ESVs are under construction in China, one at the Yantai Raffles Shipyard Ltd. in Shandong, and the second at the COSCO Shipyard Group's facility in Nantong.

GE has already delivered to the shipyards two 8V228 and six 16V228 engines, manufactured at the company's Grove City facility. “When we set out to find the best fit for the ESV power generation needs, we considered several key points to be critical to our operation. Therefore, the engine manufacturer selected absolutely had to satisfy these requirements, and that's why we chose GE's reliable engines to meet our needs,” said Remedial Offshore Chief Executive Officer Rich Altman.

The GE engines meet Remedial Offshore's design and operational criteria, such as the ability to have sufficient power available with a minimal number of engines in the existing space, while ensuring adequate redundancy.

With over 15,000 engines operating worldwide, working in some of the most challenging environments, GE's engines offered specific maintenance advantages for ESV operations, where an engine might run for extended periods of time under little or no load.

In addition, Remedial Offshore will have access to GE's worldwide parts and service supply network. Finally, each ESV will benefit from the engines' fuel-efficiency and performance that carries U.S. Environmental Protection Agency Tier II emissions compliance certification.

Altman added, “We knew this would not be an easy task to fulfill and stay within a reasonable budget. We are extremely satisfied with having made this decision and we look forward to future opportunities and joint cooperation wth GE. We will definitely draw on our relationship to refine performance and address any future operating environmental regulations hat come our way.”

“We are delighted to work with Remedial Offshore to provide engines for this novel application,” said John Manison, manager of GE Marine, Erie. “We are confident that, coupled with our outstanding service and support network, our engines will reliably meet the operating requirements for this new- generation vessel.”

The new licences cover a total of seven blocks and part-blocks in both the North Sea and the Norwegian Sea. Dana Norway has been appointed as Operator for the licence in which it holds the largest working interest.

Consequently, Dana Norway has now built a significant portfolio offshore Norway. This includes a 45% stake in the producing Jotun Oil Field, operated by ExxonMobil, and interests in a total of 8 licenses on the NCS covering 16 blocks or part blocks.

Dana’s Chief Executive, Tom Cross commented:- “Dana entered Norway in mid 2007 and, in just a short time, we have built a valuable portfolio of assets and opportunities. Our first Norwegian well, late in 2007, resulted in two oil discoveries at Storskrymten and we now look forward to exploring the new licences we have just been awarded.”

The Dana Petroleum group is now producing oil and gas from a total of 30 fields, spanning the UK, Egypt, Norway and the Netherlands. Dana is actively exploring for new oil and gas reserves in each of these countries and expects to drill a total of 17 exploration wells worldwide in 2008. In addition, the Group has exploration programmes underway in other African countries including Mauritania, Senegal and Morocco. Dana is also the largest shareholder in the independent oil company Faroe Petroleum plc, which is producing and developing gas fields in the UK and exploring for oil and gas offshore Norway, the UK, the Faroes and the Netherlands.

Valued at USD 680 million, the contracted EPC work began in November 2007 with a Limited Notice to Proceed. A full Notice to Proceed with the full project scope was provided on 07 February 2008 with a planned completion date of Q2 2011.

"We are excited to move forward on the engineering and construction phase of this Gulf Coast region LNG regasification terminal. Being selected for this project demonstrates the confidence that our customers have in the experience and abilities of the Aker Kvaerner and IHI team," said John Siffert, president of Aker Kvaerner's LNG business. "We are committed to the completion of the project to the satisfaction of our client, in a timely and safe manner."

Aker Kvaerner, Inc., a principal LNG facilities engineering and construction management firm, and IHI Inc., a market leader in the design and manufacturer of LNG storage and processing systems, are the contract parties responsible for delivering the project. Directed from Houston, Texas, design and engineering for the project will involve approximately 125 personnel from the joint venture. In addition, Aker Kvaerner Industrial Constructors, Inc. will employ a peak construction labour force of approximately 650 to complete the project.

The LNG receiving terminal project will consist of two 160,000 m3 full-containment LNG tanks and a vaporization system. Once complete, the facility will process approximately 1.5 billion standard cubic feet of gas per day, providing the Gulf Coast region with much-needed clean burning natural gas. http://www.akerkvaerner.com

The study is being jointly acquired with Libyan partners AGESCO and NAGECO under an agreement with the National Oil Corporation (NOC) of Libya. This milestone program will be acquired in several phases and will eventually provide data over all petroliferous basins in Libya. The initial phase of the program includes over 250,000 kilometers of data to be acquired in a regional grid and will cover all of offshore Libya as well as several onshore basins. Multiple aircraft will be used simultaneously to acquire the data quickly and efficiently. Data acquisition and processing of the initial phase of the program is expected to take approximately six months. View map.

Upon completion, the aeromagnetic data and interpretation will be used by oil companies for the geological evaluation of new areas for bid rounds and for complementing ongoing work programs in licensed concessions. The data will also be used by NOC for research programs.

The resort’s first filling station, for fuel company Al Maha, was originally planned to have fully buried fuel storage tanks, but due to the presence of a very high water table, the three 50,000 litre tanks are only semi-buried. This means fuel is pumped into the tanks using a positive displacement pump. The site has three multi-product dispensers and is fitted throughout with UPP Extra pipework and PetroTite containment products.

UPP is an ideal choice for locations where protection of the environment is important. At the heart of the UPP system is a highly efficient electrofusion welding system, which connects pipe and fittings to create a seamless direct burial pipe-work system that is also corrosion-free. Full details of the UPP system is at www.petrotechnik.com

The Cameron SaD Phase 1 program will cover a 100 OCS block area that contains several producing fields as well as expired leaseholds. The water depths in the survey range from 40 meters to over 200 meters. The data will be recorded with 9000 meter offsets and by utilizing the Vector-Seis recording system, full coverage around the numerous surface obstructions will be achievable. The long offsets will allow further illumination of deeper targets in the area while providing more definition to the conventional plays.

The Cameron SaD Phase 1 program will commence in March 2008 and is supported by pre-funding from multiple oil companies. Survey acquisition is expected to last approximately seven months. TGS expects to have data available for the March 2009 lease sale. http://www.tgsnopec.com/

The award marks the eleventh major FPSO design that KBR has been involved with in the past decade. Pazflor’s design is a purpose-built FPSO with a topsides weight of 32,200 metric tons. Total's Angolan subsidiary, Total E&P Angola (TEPA), awarded DSME the engineering, procurement and construction (EPC) contract to construct the vessel's moorings, hull and topsides. It is designed with a processing capacity of 200,000 barrels per day of oil, 150 million cubic feet per day of gas, and a storage capacity of about 1.9 million barrels of crude. Facilities are planned for a 20-year design life, and quarters are provided for 220 operation and maintenance personnel. First oil production on Pazflor is scheduled in 2011.

"The Pazflor FPSO is the fourth consecutive mega-topsides and second new-build FPSO awarded to KBR by DSME in the last five years," said John Rose, president, upstream for KBR. "This project builds on KBR's long history of work in Angola and reinforces the importance of this market for our company."

Pazflor includes the Perpetua, Acacia, Zinia and Hortensia fields, which lie in the eastern portion of Block 17 approximately 150 kilometers from the Angolan coast. The FPSO will be spread-moored in a depth of approximately 2500 feet atop 25 subsea oil wells, 2 gas injection wells and 22 water injection wells. DSME will construct the vessel at its fabrication yard in South Korea - For more information, visit www.kbr.com

The scope of work is to deliver a complete drilling equipment package including installation and commissioning supervision. The contracts will be executed by the Aker Kvaerner subsidiary, Aker Kvaerner MH in Kristiansand, Norway which is recognised for its field-proven drilling equipment.

"We are very pleased to have been awarded this drilling equipment contract. This confirms our excellent relations with DSME and our ability to execute projects on schedule", says Roald Amundsen, President of Aker Kvaerner MH. The drillship is scheduled for delivery third quarter of 2011.

Mr Choo Chiau Beng, Chairman and CEO of Keppel O&M, said, “With the addition of Al-Zubarah to its fleet, GDI is a step closer to realise its vision of becoming a world class drilling services provider. Keppel FELS is honoured to play an important role in helping GDI, and Qatar, to achieve its aim.” Al-Zubarah is the second KFELS B Class jackup that Keppel FELS has completed for GDI. The first rig, Al-Khor, is successfully operating offshore Qatar in the Arabian Gulf.

Keppel FELS also delivered another jackup drilling rig 10 days ahead of contractual schedule to Awilco Offshore ASA (Awilco), a member of the Anders Wilhelmsen Group. Like Al-Zubarah, this jackup rig, WilBoss, is of the KFELS B Class rig design.

Mr Tong Chong Heong, Managing Director and COO of Keppel O&M, said, “Keppel FELS aims to be the provider of choice and partner in solutions by creating value for our customers, delivering cost effective, high quality products, on time and within budget. We are happy to achieve this early delivery despite the tight market for labour and equipment.

The rig is the second of three rigs Keppel FELS is building for Awilco. The first rig, WilCraft was delivered ahead of schedule in December 2006. The third rig is scheduled for delivery in second quarter of 2009.

Marulk can give valuable additional resources in the Norwegian Sea and the well is an important part of our exploration activities in the Norwegian Sea, where we have had an active program including deep water frontier wells and wells close to existing infrastructure.

In 1992, the well 6507/2-2 "Marulk discovery" confirmed volumes of approximately 6.7 billion Sm3 of recoverable gas and 0.4 million Sm3 recoverable condensate in the upper and lower Cretaceous reservoirs. This discovery is located approximately 21 km southwest of the Norne field.

The objective of well 6507/2-4 was to appraise the extent of the gas/condensate discovery and prove additional economical reserves. The well confirmed gas and condensate in a position 4.5 km from the discovery well. The well was not tested. This is the fourth well in production licence 122, which was awarded in licensing round 10B in 1986. The appraisal well 6507/2-4 was drilled to a vertical depth of 3,584 metres below the sea surface and was completed in rocks of lower Cretaceous age. The water depth is 365 metres, and the well will be permanently plugged and abandoned. The well 6507/2-4 was drilled with the semi submersible drilling vessel West Alpha.

Eni Norge has great faith in the Norwegian Continental Shelf (NCS) and the results from the well are encouraging with respect to future development of the Marulk discovery. Marulk shows that our NCS focus gives results.

The licensees in production licence 122 are: Eni Norge AS (operator) - 20%, StatoilHydro ASA - 50% and DONG E&P Norge AS - 30%