Gulfstream Services Inc (GSI), provider of cutting edge equipment to the international oil and gas industry, has successfully completed two six figure decommissioning contracts with major oil and gas service companies, Helix Well Ops UK and Dof Subsea.

The Helix contract was part of the BP North West Hutton decommissioning project where GSI tools were used to remove 10” and 20” pipelines from the seabed. GSI’s Hydraulic Shear was an effective engineering solution in the situation due to the quick boat to boat times.

Photo: Martin Blake, operator/workshop technician, GSI,  working on GSI product

GSI equipment was used by Dof Subsea for the cutting and recovering of items on a North Sea platform including a 6” pipeline, concrete mattresses, clump weights and various small steel structures. After the assignment it was reported that the performance of GSI equipment and personnel were above expectations and caused no downtime.

Both projects were carried out in the North Sea over a three and two week period respectively.

Caroline Grant, operations manager GSI, said: “It has been a busy few months for GSI. We are delighted to be involved in such high profile projects with Helix and Dof Subsea. The efficient delivery of the projects are a testament to the effectiveness and quality of our products and staff. This is further proof that we are at the forefront of the decommissioning market.

“Since we established the GSI hydraulic shear division in 2006 we have performed over 8000 cuts in worldwide locations using our specialised decommissioning equipment. Looking ahead, we will continue to endeavour to provide first class service to all our customers.”

GSI was established in the US in 1978 and now has four bases across the states. Gulfstream Services UK was set up in January 2010 in Aberdeen to serve the international oil and gas industry and growing demand from customers in UK, Norway, Middle East, Asia and Africa.

Around 6300 subsurface cuts have been carried out and 2000 land based cuts. The deepest cut completed by the firm was 3019ft, for major oil and gas projects in the Gulf of Mexico.

GSI aims to provide innovative and cost efficient solutions to industry challenges and all of its products have evolved in line with customer requirements.

Currently the GSI global hydraulic tooling fleet consists of 26 workable shears and grapples, which are used for numerous applications within the oil and gas industry including platform and pipeline removal, slot recovery, chain cutting, wire rope cutting, salvage work and well blow out intervention.

GSI recently increased its staff numbers in response to business growth – the company currently has 12 members of staff and plans to expand this by a further three in the coming months.

Buccaneer Energy Limited (ASX:BCC) advises that the Alaskan Oil and Gas Conservation Commission ("AOGCC") has inspected and certified the Endeavour jack-up rig for operations within Alaskan state waters, this was the final certification required for the Endeavour to be able to commence drilling operations.

The Cosmo # 1 well spud at approximately midday EST on 13 May 2013 (Sydney) and is currently at 600' drilling ahead.

The Company will provide weekly drilling updates commencing on Tuesday 21 May 2013.

The Cosmopolitan Project ("Cosmo") is located in 80' feet of water approximately 30 miles to the north west of Homer. Cosmo is jointly owned with privately owned Fort Worth, Texas based BlueCrest Energy II, LP ("BlueCrest") owning a 75% working interest and Buccaneer a 25% working interest, with Buccaneer as the Operator for the project.

Cosmo # 1 Well Plan

The Cosmo # 1 well is a vertical well that has a targeted Total Vertical Depth of 8,000' ("TVD"), the well is anticipated to take approximately 45 days to drill and test.

Surface casing will be set at 800' after which the well will be drilled to the top of the Tyonek Formation ("Tyonek") at 2,000' where casing will again be set. The first gas Tyonek gas zone should be intersected at approximately 2,150' with multiple gas zones anticipated intersected to 6,000'.

Casing will be set at approximately 6,000' before drilling through the proven oil bearing Starichkof and Hemlock Formations, and will reached the target depth of 8,000' after drilling the prospective West Foreland Formation. The current plan is to take oil cores to augment the reservoir data to further optimize the future oil plan of development. At this stage it is not planned to flow test the oil formations.

On completion of drilling and logging operations the well will be plugged back to the bottom of the Tyonek gas formation. Gas zones within the Tyonek Formation that are identified as potentially commercial through drilling and logging will then be perforated and flow tested. If successfully tested the well will be temporary abandoned as a future gas producer.

Historical Technical Appraisal and Drilling

The Cosmopolitan oil accumulation was initially discovered by Pennzoil by exploration drilling in 1967.

- Oil reservoirs are the Oligocene Lower Tyonek (Starichkof sands);

- Reservoirs are non-marine sandstones with 750' of vertical oil column;

- Oil gravity is 24-27 degrees API; and

- Pioneer estimated OOIP at 360 MMBO;

An offset well (Starichkof State Unit #1) was drilled by Pennzoil in 1967 to the northeast of the discovery well:

- Well was low on the structure and wet in the oil zones;

- Several cores in the shallower Tyonek Formation revealed excellent rock properties with porosities >20% and permeability of 100 - 1000 md;

- Conventional core was taken in the Lower Tyonek Starichkof Formation with average porosity >14% and average permeability > 36 md; and

- Gas cut mud was tested from Tyonek intervals suggesting possible gas higher on structure.

The accumulation was tested again by Arco in 2001:

- Hansen #1 well was drilled from onshore with long reach and found oil in the Starichkof and Hemlock sands;

- 2 Drill Stem Tests ("DST") in the Starichkof sands tested at 200-300 BOPD; and

- Follow up DST's in 2002 found Hemlock sands oil which tested at 300 BOPD and a subsequent Starichkof test of 125 BOPD.

The accumulation was tested again by ConocoPhillips who acquired Arco assets in 2003:

- Hansen #1A was sidetracked out of the original Hansen #1 with a long reach well drilled from onshore;

- DST in the Starichkof/Hemlock intervals tested at rates up to 1000 BOPD; and

- Extended production test stabilized at 550 BOPD.

Pioneer acquired a 40 square mile 3D survey covering the structure in 2005 and obtained a 100% ownership position in 2007

Additional drilling occurred by Pioneer in 2010:

- Hansen #1A-L1 was drilled as a long lateral out of the #1A sidetrack;

- The #1A-L1 is a horizontal well drilled within the Starichkof interval;

- An extended production test was conducted after drilling and stimulation (frac); and

- Results were a cumulative 33,504 BO produced with no water at 250 BOPD + 1 MMcfg/day additional to the Hansen #1A extended production test of 550 BOPD.

Applus RTD, a global leader in the provision of integrity technology services, has unveiled its most sophisticated ultrasonic 3D inspection technology to date – the latest addition to its revolutionary NDT3D technology range.

The RTD IWEX (Inverse Wave Field Extrapolation) is an emerging Non Destructive Testing (NDT) technique that allows detailed inspection and mapping of defects within critical pieces of pipework.

The system increases the probability of detection of defects within welds, as well as more accurately detailing the size, position and characterization of faults. It has the potential to save operators millions of dollars by reducing the number of welds being rejected in new construction pipelines both onshore and offshore.

Rienk de Vries, technical director at Applus RTD, said: “RTD IWEX provides users with a reconstructed image of the inspected object, giving a clearer insight into the scale and nature of any existing defects than is currently possible.

“By utilizing this technology more accurate results in relation to the size and position of the defect can be gained throughout the inspection process.”

The product has been designed to tackle a number of known client issues during processes such as pipeline construction and strain-based pipeline designs and can be utilized during operations for the oil and gas and renewables sectors.

Mr de Vries added: “We are committed to a program of technological research and development aimed at delivering new techniques that maximize the effectiveness and value of our services.

“Ensuring the integrity of the infrastructure being used in the global energy industry is critical to the success of E&P activity and it is of paramount importance to Applus RTD that we not only contribute to improved standards, but set the bar within the ultrasonic NDT arena.

The RTD IWEX is the product of six years of research and development and has already been validated by several oil majors.

The Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE), Noble Energy, Inc. and the Helix Well Containment Group (HWCG)  has announced the successful completion of a full-scale deployment of critical well control equipment to assess Noble Energy’s ability to respond to a potential subsea blowout in the deepwater Gulf of Mexico. BSEE Director James Watson confirmed that the HWCG capping stack deployed for the exercise met the pressurization requirements of the drill scenario, marking successful completion of the exercise.

The unannounced deployment drill, undertaken at the direction of BSEE, began April 30 to test the HWCG capping stack system – a 20-feet tall, 146,000-pound piece of equipment similar to the one that stopped the flow of oil from the Macondo well following the Deepwater Horizon explosion and oil spill in 2010. During this exercise, the capping stack was deployed in more than 5,000 feet of water in the Gulf of Mexico. Once on site, the system was lowered to a simulated well head (a pre-set parking pile) on the ocean floor, connected to the well head, and pressurized to 8,400 pounds per square inch.

“Deployment drill exercises like this one are essential to supporting President Obama’s commitment to the safe and responsible development of offshore resources,” said Director Watson. “BSEE continually works to ensure that the oil and natural gas industry is prepared and ready to respond with the most effective equipment and response systems.”

BSEE engineers, inspectors and oil spill response specialists are evaluating the deployment operations and identifying lessons learned as the bureau continues efforts to improve safety and environmental protection across the offshore oil and natural gas industry.

“The quick and effective response to a deepwater well containment incident, demonstrated during the drill, was enabled by collaborative communication and planning between the industry and regulatory agencies with a focus on solutions-based outcomes,” said John Lewis, senior vice president of Noble Energy. “BSEE, the U.S. Coast Guard, Louisiana Offshore Coordinator’s Office and Noble Energy brought unique perspectives together in a Unified Command structure to achieve a shared goal. Through excellent coordination within the Incident Command System structure that included elevating the Source Control Chief to report directly to Unified Command, the dedication of hundreds of people and activation of the HWCG rapid response system, all objectives were met.”

“HWCG’s ability to quickly and effectively respond to a call from Noble Energy and every operator in our consortium is made possible by a combination of the mutual aid agreement committed to by each consortium member and the contracts we have in place for equipment that is staffed and working in the Gulf each day,” said Roger Scheuermann, HWCG Commercial Director. “Mutual aid enables members to draw upon the collective technical expertise, assets and resources of the group in the event of an incident. Utilizing staffed and working vessels, drilling and production equipment helps ensure there is no down time for staffing or testing equipment readiness in a crisis situation. ”

In accordance with the plan, all 15 member companies were activated for this incident through the HWCG notification system.

For the safety of personnel and equipment, a Unified Command comprised of BSEE, the US Coast Guard, Louisiana Oil Spill Coordinators Office and Noble Energy decided to temporarily hold operations May 2 and 3, 2013 due to rough weather over the Gulf of Mexico. The safety of personnel remained a top priority throughout the exercise.

Since the Deepwater Horizon tragedy in 2010, BSEE has worked to implement the most aggressive and comprehensive offshore oil and gas regulatory reforms in the nation’s history. This deepwater containment drill tested one critical component of enhanced drilling safety requirements. For more information about the bureau’s efforts to improve safety and environmental protection, please visit: http://www.bsee.gov.

Research is Part of a Long-Standing, Interagency Collaboration

Scientists have returned from a 15‑day research expedition in the northern Gulf of Mexico with the best high-resolution seismic data and imagery ever obtained of sediments with high gas hydrate saturations.

Map: The USGS Gas Hydrates Project integrates across USGS mission areas, programs, and regions. The stars indicate the locations of personnel involved in the Gas Hydrates Project. Within the US, much of the research focuses on the Gulf of Mexico and Alaska, which represent marine and permafrost-associated settings for gas hydrates, respectively.

The expedition and the data and imagery collected resulted from long-standing cooperation between the U.S. Department of the Interior’s U.S. Geological Survey (USGS) and Bureau of Ocean Energy Management (BOEM) and the U.S. Department of Energy (DOE). This collaboration aims to advance scientific understanding of gas hydrates, an important potential future energy resource.

Gas hydrates are ice-like substances formed when certain gases combine with water at specific pressures and temperatures. Deposits of gas hydrates are widespread in marine sediments beneath the ocean floor and in sediments within and beneath permafrost areas, where pressure-temperature conditions keep the gas trapped in the hydrate structure. Methane is the gas most often trapped in these deposits, making gas hydrates a potentially significant source for natural gas around the world.

“This expedition represents a significant milestone,” said USGS Energy Resources Program Coordinator Brenda Pierce. “The data and imagery provide insight into the entire petroleum system at each location, including the source of gas, the migration pathways for the gas, the distribution of hydrate-bearing sediments, and the traps that hold the hydrate and free gas in place. The USGS has a globally recognized research effort studying gas hydrates in settings around the world, and this project combines our unique expertise with that of other agencies to advance research on this potential future energy resource.”

The recently completed expedition was planned jointly by USGS, DOE, and BOEM, and was executed by USGS.  Using low-energy seismic sources, USGS scientists collected details about the nature of the gas hydrate reservoirs and about geologic features of the sediment between the reservoirs and the seafloor. The new data also provide information about how much gas hydrate exists in a much broader area than can be determined from using standard industry seismic data, which is typically designed to image much deeper geologic units.

“Understanding the nature and setting of deepwater gas hydrates is central to the National Methane Hydrates R&D Program, which is led by DOE and managed by Fossil Energy’s National Energy Technology Laboratory,” said Christopher Smith, DOE’s Acting Assistant Secretary for Fossil Energy. “Over the past 8 years, research carried out under this program has resulted in significant advances in our understanding of methane hydrates, their role in nature, and their potential as a future energy resource. This success is largely due to an unprecedented level of cooperation among federal agencies, industry, national laboratories, and academic institutions.”

“The high-resolution nature of the data acquired through this interagency project will uniquely inform the BOEM effort to assess the resource potential of gas hydrates on the U.S. Outer Continental Shelf,” said Renee Orr, Chief, Strategic Resources Office, BOEM.

The data were collected at two locations in the Gulf of Mexico where the three federal agencies partnered with an industry consortium to conduct a drilling expedition in 2009. That expedition discovered gas hydrate filling between 50 and 90 percent of the available pore space between sediment grains in sandy layers in the subsurface. These reservoirs are expected to be representative of the 6,700 trillion cubic feet of gas that BOEM estimates is housed in gas hydrates in sand-rich reservoirs in the northern Gulf of Mexico.

The new data are being used to refine estimates of the nature, distribution, and concentration of gas hydrate in the vicinity of the 2009 drill sites. This will help assess how useful specialized seismic data may be to estimating hydrate saturations in deepwater sediments.

In coming years, the three agencies will continue their collaborative investigation of gas hydrates in the northern Gulf of Mexico and other locations across the world.

Learn more about USGS research on gas hydrates and energy at locations around the world.

Crowley Maritime Corporation's petroleum services group is entering the Liquefied Natural Gas (LNG) market by acquiring Carib Energy LLC.  Florida-based Carib Energy, founded in 2011, was the first company to receive a small scale, 25-year, LNG export license from the U.S. Department of Energy (DOE) for LNG transportation from the U.S. into Free Trade Agreement (FTA) countries.

While Crowley’s overall strategic focus on the LNG market will span several of its diversified business lines and leverage its storied history and success in the marine, project management, energy and transportation fields, Carib Energy provides an induction into the emerging energy market from which the company can grow its concentration on LNG transportation.

A Crowley LNG services group has been formed within Crowley’s petroleum services business unit. It is being headed up by Vice President of Business Development Matt Jackson, who reports to Rob Grune, senior vice president and general manager, petroleum services. This team will marshal Crowley’s extensive resources to serve the LNG market through LNG vessel design and construction; transportation; product sales and distribution, and full-scale, project management solutions.

“Crowley has a myriad of business lines, each with overlapping expertise perfectly positioned to develop a strong footprint in the LNG market,” said Tom Crowley, company chairman and CEO. “Whether it’s designing the next LNG bulk transport vessel, transporting ISO tanks via Crowley’s regularly scheduled liner service, arranging special carriage via our global logistics network or providing project solutions for LNG discovery and extraction; Crowley has the service portfolio to provide turnkey solutions within the LNG space.”

The acquisition of Carib Energy, which becomes a wholly owned subsidiary of Crowley Petroleum Services, now provides Crowley an immediate book of business for the supply, transportation, and distribution of LNG via 10,000 gallon ISO tanks.  While Carib Energy has a pending DOE application to supply LNG transportation services into non-FTA countries, its current licensing allows them, and now Crowley, to supply cost-efficient, environmentally friendly LNG from the U.S. to both commercial and industrial customers within the Caribbean and Central and South America – all countries where LNG is an attractive commodity thanks to its low price point in the face of growing power supply costs.  Carib Energy is also cementing its involvement in future LNG fuel bunkering for ships transiting between the U.S. and Caribbean markets.

“The Carib Energy acquisition is an exciting opportunity for Crowley to utilize a combination of its core competencies including marine solutions, logistics planning and execution and associated technical and project management capabilities in an area that is by all measures growing rapidly both within the U.S. and abroad,” said Grune. “We look forward to playing a pivotal role with both new and existing customers as they strive to provide safe and reliable LNG distribution assets and services.”

As part of the Carib Energy acquisition, Greg Buffington (shown), the company’s president, will join Crowley as vice president of Carib Energy, reporting to Jackson. Buffington will continue to develop and expand the company’s Caribbean and Central America opportunities for small-scale LNG applications.  His experience is deeply rooted within the international propane gas industry where he spent 31 years in varying capacities. He was the founder of EFG Industries, an international supplier of liquefied petroleum gas (LPG) equipment, engineering and plant construction.

“We are very pleased to welcome Greg to the Crowley family,” said Jackson.  “He shares our understanding of the exponential business potential for LNG as well as our corporate values. He knows our ‘One Crowley, One Team’ approach will allow us to leverage a multitude of experience towards a common goal of success within this vastly untapped energy market.”

LNG facts from the Center for Liquefied Natural Gas (CLNG): LNG, or liquefied natural gas, is natural gas that is cooled to -260° Fahrenheit until it becomes a liquid and then stored at essentially atmospheric pressure. Converting natural gas to LNG, a process that reduces its volume by about 600 times allows it to be transported. Once delivered to its destination, the LNG is warmed back into its original gaseous state so that it can be used just like existing natural gas supplies. When returned to its gaseous state, LNG is used across the residential, commercial and industrial sectors for purposes as diverse as heating and cooling homes, cooking, generating electricity and manufacturing paper, metal, glass and other materials. LNG is not stored under pressure and it is not explosive. LNG vapors (methane) mixed with air are not explosive in an unconfined environment. When exposed to the environment, LNG rapidly evaporates, leaving no residue on water or soil.

Gov. Bobby Jindal and Wolverine Terminals LLC General Manager Terry Wilson has announced the company will make a $30 million capital investment to establish a crude oil terminal and blending operation on a 15-acre Mississippi River site in St. James Parish. Wolverine will create 20 new direct jobs, with an average annual salary of $62,000, plus benefits. LED estimates the project will result in 18 new indirect jobs for a total of 38 new jobs. In addition, the project will create an estimated 100 construction jobs.

Gov. Jindal said, "This project is more great news for St. James Parish and our entire state. Wolverine Terminals joins a long list of companies that recognize Louisiana as the best state in the country for a top-notch workforce, an unmatched energy infrastructure and an outstanding business climate. We're proud to welcome Wolverine Terminals and its investment partners to our state as they help us continue our tremendous economic momentum by creating great new jobs and opportunities for our people."

The Wolverine Terminals project is supported by the following energy investment companies: Gulfport Energy Corp. of Oklahoma City and Wexford Capital LP of Greenwich, Conn. The project will entail rail and dock facility improvements along with storage tank construction that will enable the company to receive crude oil shipments by rail from Canadian and U.S. locations and to ship blended oil products via barge to domestic customers.

"We look forward to working in concert with the state and parish in creating jobs for the area," Wilson said.

LED began discussions with Wolverine Terminals about the potential project in December 2012. To secure the project, the state offered the company participation in Louisiana's Quality Jobs Program. Construction will begin in the third quarter of 2013 and be completed by the end of the second quarter in 2014. Hiring will be completed as the company initiates commercial operations at the Paulina site in the second quarter of 2014. With five storage-and-blending tanks, Wolverine will provide a total capacity of 425,000 barrels of crude oil at its St. James Parish facility.

"We are pleased to welcome Wolverine Terminals LLC to our Parish," St. James Parish President Timothy Roussel said. "The decision to choose St. James Parish for this project is not a surprise, as our resources such as the Mississippi River have proven to be a major attraction for Louisiana development. Although Wolverine Terminals will receive our full support during the planning, construction, and operating phases, the community's best interest will remain our top priority. We look forward to the opportunities this project will bring as well as a long and prosperous partnership."

For business inquiries about the Wolverine Terminals project, contact Terry Wilson at 225.394.0562 or This email address is being protected from spambots. You need JavaScript enabled to view it. with questions about operations or Glen Perry at 403.930.6437 or This email address is being protected from spambots. You need JavaScript enabled to view it. with questions about commercial opportunities.

Statoil and operator ExxonMobil have decided to sanction the Julia field development in the Gulf of Mexico.

The field, located approximately 200 miles south of New Orleans, Louisiana, was discovered in 2007 and is estimated to have nearly six billion barrels of resource in place.

Jason Nye, senior vice president, Statoil U.S. Offshore

 The announcement confirms the agreement between operator Exxon Mobil Corporation and Statoil to proceed with field development, estimated to take approximately three years. The partners each own 50 percent of the field.

 Julia will be a subsea tieback to the Jack and St. Malo floating production platform, located approximately 15 miles away, which is operated by Chevron U.S.A. Inc.

Statoil also is a co-owner in the Jack and St. Malo developments, sanctioned in 2010.

"We are very pleased to move ahead with the first phase of this important development," said Jason Nye, senior vice president, Statoil U.S. Offshore. "The Julia field is a strong addition to our growing portfolio in the Gulf of Mexico. Julia has a substantial long-term production potential which is expected to be fully realized through the application of technology to unlock its full potential."

Drilling operations are planned to start in 2014, and production start-up is planned for 2016. The lifetime of the Julia field is estimated to be up to 40 years, with an initial production rate of up to 34,000 barrels of oil per day.

Facts about the Julia field

Discovered in 2007.

The total reservoir is estimated to contain nearly six billion barrels of resource in place.

Investment decision in April 2013, production start-up in 2016.

BP and partners Total, Petrobras and Petrogal were named winning bidders for eight deepwater blocks offshore Brazil in the Brazilian National Petroleum Agency’s (ANP’s) 11th bid round. BP will be operator in two of the blocks.

The companies have committed to explore concession blocks FZA-M-57, FZA-M-59, FZA-M-86, FZA-M-88, FZA-M-125, and FAZ-M-127 in the Foz do Amazonas basin, BAR-M-346 in the Barreirinhas basin, and POT-M-764 in the Potiguar basin, for oil and gas resources, with the right to develop any commercial discoveries under the Brazilian concession regime.

BP will be operator with a 70% stake in block FZA-M-59, and in block BAR-M-346, with a 50% stake.

“BP is delighted with this result. It will increase our frontier exploration exposure along Brazil’s equatorial margin and plays to our strengths in deepwater. We look forward to a successful exploration programme working with our partners Total, Petrobras and Petrogal,” said Mike Daly, BP’s Executive Vice President of Exploration.

Today’s winning bids follow BP’s re-entry into the Brazilian upstream in 2011 with the purchase of interests in 10 blocks from Devon Energy and the subsequent farm-in to four Petrobras-operated deepwater blocks in the Brazilian equatorial margin in 2012.

“This is an exciting outcome for BP. It reaffirms our long-term partnership with Brazil, expanding our upstream portfolio to 22 E&P concessions in seven different basins, in addition to our biofuels, lubricants, aviation and marine fuel businesses,” added Guillermo Quintero, BP Brazil Regional President.

BP and its partners now expect to work with the ANP to finalise the awards. The signing of the contracts, in which BP will participate through its Brazilian subsidiary BP Energy do Brasil Ltda., is expected to take place in August 2013.

Table of the awarded blocks:

Foz do Amazonas basin - SFZA-AP1

Barreirinhas basin - SBAR-AP2

Potiguar basin -

Cal Dive International, Inc. (NYSE:DVR) announced today that it has been awarded two additional contracts from Pemex Exploración y Producción that are expected to generate combined total revenues of approximately $188 million.

The first contract is for the procurement, installation and commissioning of 47 kilometers of 20 inch subsea pipeline and associated tie-ins to an existing platform. This contract is expected to generate revenues of approximately $129 million and will utilize two of the Company’s vessels as well as a third party vessel. The offshore construction is expected to commence in the third quarter 2013 with a portion of the work expected to be performed during the first quarter 2014.

The second contract is for the procurement, installation and commissioning of nine kilometers of two medium diameter subsea pipelines and associated tie-ins to existing platforms. This contract is expected to generate revenues of approximately $59 million and will utilize a third party vessel and a Company dive support vessel. The offshore construction for this contract is expected to commence in the fourth quarter 2013 and is expected to be completed by the end of the second quarter 2014. On a combined basis, approximately 50% - 60% of the contracts are expected to be performed during 2013.

Quinn Hébert, Chairman, President and Chief Executive Officer of Cal Dive, stated, “With the $63 million Pemex contract we announced in March, total contract awards with Pemex this year currently stand at $250 million. These awards increase our total Company backlog to over $400 million, our highest level in five years. We believe these awards demonstrate Pemex’s confidence in Cal Dive as a reliable contractor. These recent contract awards not only secure work for the second half of 2013, but also provide significant visibility for the first half of 2014 when our domestic business is historically slow due to the winter work season. Also, we continue to bid for additional work in Mexico that would mostly benefit our 2014 results.”

FMC Technologies, Inc. (NYSE: FTI) announces that it has received a subsea equipment order from ExxonMobil Corporation (ExxonMobil) for its Julia development.

The Julia field is located in the Gulf of Mexico Walker Ridge area in approximately 7,000 feet (2,100 meter) water depth. FMC Technologies' scope of supply includes six subsea trees, a manifold and associated tie-in equipment.

"FMC Technologies is pleased to provide ExxonMobil with subsea systems for this offshore project," said Tore Halvorsen , FMC Technologies' Senior Vice President, Subsea Technologies. "We look forward to supporting ExxonMobil as they overcome the technological challenges of this ultra deepwater development."

Market-leading energy services company Proserv has won a multi-million dollar contract in Angola, underpinning the company’s fast-evolving subsea status and increasing demand for its sampling system innovations.

Proserv is to design and manufacture a subsea sampling system for BP’s PSVM field development which, with a water depth of 2,000 meters, is believed to be the deepest offshore project in Africa.

The system, which is being designed, manufactured and tested by Proserv’s dedicated teams in Aberdeen and Aberdeenshire, can go to a maximum water depth of 2,500 metres as well as interface with two and four-slot subsea manifolds. It is also fully compliant with corrosion society, NACE International, and meets the high engineering standards set by the American Petroleum Institute.

David Lamont, chief executive officer at Proserv which has won a contract to design and manufacture a subseasampling system for BP’s PSVM field in Angola.

Chief executive officer at Proserv, David Lamont, said: “This contract win represents another significant achievement for Proserv. It underpins the strong track record we are continuing to build around the world by consistently delivering robust technology systems and services for customers on time and to the highest standards including overall compliance with very stringent technical specifications.

“With an established track record spanning over 35 years in the sampling services sector, we have strengthened our capabilities and expertise through organic growth and strategic acquisitions. This has resulted in us capturing a large share of the subsea market and with the increasing demand for flow assurance and reservoir analysis, we fully intend to set the pace as the leading global player in the subsea sampling field.”

Proserv’s sampling system will interface with the subsea production system to support the monitoring of PVT properties in the production fluid as various levels of these elements can cause flow assurance issues such as scale build up.

The cylinders for the sampling system will be designed at Proserv’s specialist manufacturing center in Greenbank, Tullos, with the whole sampling system to be manufactured and assembled at the company’s Birchmoss facility in Aberdeenshire.

The contract is the second one that Proserv has undertaken for BP Angola on the PSVM development. The company previously provided two similar subsea sampling systems for Block 18 through FMC Technologies.

Proserv, which is headquartered in Westhill, Aberdeenshire, has fast emerged as a leading industry specialist in exploration & production, drilling, and infrastructure technical solutions and services to the global energy industry.

The company has experienced exceptional growth over the past 12 months particularly in the subsea services sector.

Statoil was the highest bidder on 6 licenses in Brazil's 11th licensing round, the first licensing round in the country since December 2008. With the new licenses, Statoil has strengthened its position in the Espirito Santo basin.

The award in Brazil's 11th licensing round reflects Statoil's extensive application and ambition of long-term growth in Brazil. Out of the six licenses awarded in Espirito Santo, Statoil is the operator for four and partner in two of the licenses.

"We are very pleased with the outcome," says Tim Dodson, executive vice president for Exploration in Statoil.

 "The award of the blocks in the Espirito Santo basin is in line with Statoil's exploration strategy to build on core positions in prolific and proven basins."

Statoil's application for exploration licenses in the basin is based on established and new geological play models.

"The new positions underscore our ambition to grow in Brazil, which we see as a region for long-term growth.

"Access to new quality acreage is an essential prerequisite for further value creation through exploration activities and for increasing Statoil's international production level from key clusters such as Brazil," says Thore E. Kristiansen, senior vice president South America and president for Statoil Brazil.

In December 2012 Statoil acquired a 25% participating interest from Vale SA in BM-ES-22A in the Espirito Santo Basin. Petrobras is the operator with 75%.

The farm-in is pending Brazil National Agency of Petroleum, Natural Gas and Biofuel (ANP) approval. BM-ES-22A is adjacent to the BM-ES-32 license where Statoil is partner and which holds the Indra discovery.

"These new licenses in the Espirito Santo basin give us a significant acreage position in a proven hydrocarbon basin. They have the potential to provide large-scale additional resources close to our existing discoveries, which with success will result in Statoil building a new core position," says Dodson. 

Statoil operates the Peregrino field in Brazil, which came on stream in April 2011, and Statoil is currently the largest international operator in the country. Statoil is also operator of some of the world's largest oil and gas discoveries over the last couple of years and has a strong safety and environmental record.

The 11th bidding round on 14 May was conducted by the ANP. The concession agreements from the 11th licensing round are scheduled to be signed in August 2013.

In the 11th licensing round in Brazil Statoil has been awarded:

Six exploration licenses in the Espirito Santo basin, of which four as operator and two as partner.

The licenses are located in the deepwater sector of the Espirito Santo basin, close to the licenses BM

ES-32 and BM-ES-22A which are operated by Petrobras and in which Statoil is already a partner.

The blocks have an exploration phase of seven years, divided in to two periods of five years and two

years, and the total well commitment for the six licenses is 10 wells.

Consortium:

ES-M-596: Petróleo Brasileiro S.A.* (50%), Statoil Brasil Óleo e Gás Ltda. (50%)

ES-M-598: Statoil Brasil Óleo e Gás Ltda.* (40%), Petróleo Brasileiro S.A. (40%), Queiroz Galvão Exploração e Produção S.A. (20%)

ES-M-669: Petróleo Brasileiro S.A.* (40%), Total E&P do Brasil Ltda. (25%), Statoil Brasil Óleo e Gás Ltda. (35%)

ES-M-671: Statoil Brasil Óleo e Gás Ltda.* (35%), Petróleo Brasileiro S.A. (40%), Total E&P do Brasil Ltda. (25%)

ES-M-673: Statoil Brasil Óleo e Gás Ltda.* (40%), Queiroz Galvão Exploração e Produção S.A. (20%), Petróleo Brasileiro S.A. (40%)

ES-M-743: Statoil Brasil Óleo e Gás Ltda.* (35%), Petróleo Brasileiro S.A. (40%), Total E&P do Brasil Ltda. (25%)

In the construction of a subsea project, one challenge is the long delivery time of large steel forgings used for key components. This is mainly due to compliance with oil companies’ individual requirements. DNV is now inviting the subsea industry to jointly obtain synergies by developing a best-practice approach. The aim is to reduce delivery time and production costs and improve material quality, thus reducing the risk throughout the supply chain.

Due to quality concerns, the end users of subsea systems are stipulating company-specific requirements for subsea forgings, such as those used for X-mas trees. “This has made the stocking of prefabricated forgings and thereby shorter lead times difficult for the vendor industry. The typical delivery time can be in excess of seven months, and has a high potential for being shortened,” says Bjørn Søgård, business development manager at DNV’s Well, Pipelines and Subsea Section.

“One pre-requisite for shortening the lead times and effective project execution is the timely availability of forgings that meet all likely end users’ quality requirements. A unified set of requirements across the industry would be a solution with a synergetic effect, make procurement easier and help reduce quality challenges,” he points out.

On this basis, and in response to requests from key stakeholders in the subsea industry, DNV has now established a Forging-material Joint Industry Project (JIP). It will run for 14 months and include valuable contributions from major oil companies, subsea contractors and manufacturers of steel forgings. In addition, DNV will contribute the advice of its own pool of subject-matter experts. The conclusions will be presented in a Recommended Practice available to the industry.

Søgård explains that the core goal for all participants is to improve the quality, cost and delivery times of forgings for the subsea industry. “A unified approach will also help limit the risk of failure during fabrication, subsea installation and operation. The outcome will not only benefit the manufacturers and sub-suppliers, but also improve the end-customers’ way of specifying their requirements regarding mechanical loads, interfaces with other materials, environmental issues, cathodic protection, cyclic loading, etc,” he concludes.

The adoption of a unified material standard with a consistent methodology to manage all steps in the supply chain processes will help ensure consistently high and repeatable quality across the industry and geographical regions and build confidence into the final product. The JIP will be run with participation from the industry based in both Houston, USA and Oslo, Norway.

Subsea 7 S.A. (Oslo Børs: SUBC) announces a contract award by Pemex to its Mexican joint venture valued at approximately $90 million.

The contract comprises the engineering, fabrication and installation of an 8km pipeline, related risers, two slug catchers¹ and two cantilever structures for the Line 67 Project in the Bay of Campeche. This is the second contract awarded to the joint venture.

Project management and engineering will be handled from the joint venture’s offices in Ciudad del Carmen and Houston. Offshore operations are due to commence in the third quarter 2013, with pipelay activities being conducted in the fourth quarter 2013 with Seven Borealis.

Ian Cobban, Subsea 7´s Vice President Gulf of Mexico, said “Subsea 7 Mexico is pleased to be awarded its second contract in Mexico. We look forward to delivering the project in a safe and timely manner, and in so doing, strengthening our relationship with Pemex.”

¹ a slug catcher is a storage vessel used to separate oil, water and gases and regulate flow within a pipeline

New research reveals the impact of post-Macondo reform

US oil and gas professionals are losing their appetite for risk and are worried about rising operating costs, as they grapple with the consequences of a tougher, post-Macondo regulatory regime, according to new research published by GL Noble Denton.
Despite the new regulations, the vast majority believe that the US will continue to be a leading investment destination, and that the changes are necessary to improve the safety and reputation of the industry, according to the report.

The findings come from a study, Reinventing Regulation: The impact of US reform on the oil and gas industry, which was undertaken on behalf of GL Noble Denton, the independent technical advisor to the oil and gas industry.
The research provides a snapshot of industry sentiment towards the issue of new regulation being introduced in the US. It is based on a survey of more than 100 senior oil and gas professionals with operations in the US, and in-depth interviews with 10 industry executives, analysts and academics.

Headline findings:

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More than eight in 10 (85%) expect the US regulatory regime to get a lot tougher over the next two years, but only 17% disagree that the US will remain a leading investment destination 
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More than six in 10 (61%) believe the changing regime will have ‘somewhat’ negative or ‘highly’ negative effects on their business over the next two years 
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Almost eight in 10 (78%) believe regulatory changes will lead to greater administrative workload
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More than eight in 10 (82%) believe compliance costs will increase and nearly six in 10 (57%) believe the changes will affect their appetite for risk taking
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Almost half (47%) believe the new regime will increase safety in the industry 
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Only one in 10 believe the US authorities are doing a good job of preparing the industry for the new measures
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Almost eight in 10 (76%) said they favoured a performance or goal-orientated approach to compliance, where safety and environmental targets are clearly defined, over a more prescriptive stance. The latter is more typical in the US regulatory environment.

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Business impact

The US government is implementing a raft of regulatory measures in the wake of the Macondo incident in 2010, with the aim of transforming the industry’s safety culture. Oil and gas operators are now required, for example, to demonstrate that they are prepared to deal with a blowout and worst-case discharge, while revising their approaches to everything from well design and workplace safety to corporate accountability.


According to GL Noble Denton’s research, operators believe the US regulatory regime will get tougher over the next two years, as new rules continue to be implemented.

One likely consequence of the changes will be a rise in mergers and acquisitions (M&A) among oil and gas operators, as growing compliance costs accelerates consolidation. Almost six in 10 (57%) US-based oil and gas professionals surveyed for the research believe that M&A will increase as only larger players will be able to afford to compete for business under the new regulatory regime.

Positive change

Despite the impact of the new regulation, many oil and gas professionals operating in the US believe the changes will help to restore confidence in the industry. Almost half (47%) of those polled said the measures will improve overall safety compared with 35% who did not (a further 18% were undecided). Some operators are already adopting these tougher rules globally, in order to gain a competitive advantage over their rivals.

While some fears remain for a slowdown in investment as a result of the reforms, this is a relatively minor concern. Exactly half of the research participants believe investment in the US is set to remain constant or increase – far greater than the 25% who think that investment will decrease.

Arthur Stoddart, GL Noble Denton’s Executive Vice President for the Americas, said: “It is inevitable that the devastating Macondo oil spill would incur a strong regulatory reaction. No government could fail to act in the wake of such an incident. The regulations being implemented in the US present new challenges for oil and gas operators in terms of rising costs and workloads, but these changes are absolutely necessary to improve safety and prevent a future oil spill.

“As the new rules continue to come into force over the next two years, the sector will need to adapt to survive in a new climate. Increasing compliance costs, burgeoning legal risks and a greater administrative workload are just some of the effects that industry professionals expect to encounter. Our research shows that smaller oil and gas companies operating in the US are most likely to feel the impact of these burdens.

“Despite these challenges, there are clear opportunities for business growth in the US, and the country remains a leading operating destination for oil and gas companies. Evidence of this is seen in the strong rise in the number of on and offshore drilling permits issued to operators over the past year, suggesting a continued and healthy appetite for investment.”

Download a complimentary copy of Reinventing Regulation from: www.gl-nobledenton.com <http://www.gl-nobledenton.com>