Land Rigs: May 9, 2013

Thursday, May 9, 2013

Local Participation Push for Major Australian Developments

Leaders of Australia's oil and gas industry are working together in an effort to develop methods towards increasing the amount of local content on major developments.

Locally based suppliers servicing the growing liquefied natural gas sector in Western Australia (WA) have expressed concern in recent years about being overlooked for development contracts.

Developers have cited the high Australian dollar, high labor costs and rising energy costs as reasons for opting to award contracts to competing foreign companies, often from Asia.

Despite these obstacles, developers have been urged to do more to increase local participation in projects.

Local suppliers are also being encouraged to develop a better understanding of the criteria to help them win contracts.

The issue was a key topic at the Australasian Oil & Gas Conference in Perth recently where industry groups, government representatives, and oil and gas companies discussed how more local participation could take place.

Paul Johnson, the Australian Government's Energy Resources Supplier Advocate, spoke at the conference and believes oil and gas developers need to take into account the capability and capacity of Australian suppliers if they want to boost the level of local content on their projects.

Johnson, who was appointed to this position in August of last year, said there was much good work happening in the sector to raise the capability of Australian firms to win work, but more could be done by both developers and suppliers.

"Project developers should take into account the limitations faced by Australian suppliers in undertaking large procurement packages, accessing the necessary finance and obtaining sufficient numbers of skilled workers," Johnson said.

"Small adjustments to the way projects are designed, engineered and procured can make a big difference to local suppliers.

"Early consideration of what can be done here should inform the design and engineering approach and basing some of the procurement team in Australia will lead to better engagement with local suppliers."

While major developers have been questioned for the amount of local content on their projects, Chevron reinforced its commitment to local suppliers through its conference presentation.

Colin Beckett, Chevron's general manager at the Gorgon LNG development, explained that the project had so far awarded $18.7 billion (AUD $18 billion) in contracts to local suppliers and created 9.000 jobs in the country.

However, he conceded that many Australian companies had not met the pre-conditions for tendering for work, with reasons including a lack of experience or capacity.

To assist in preparing local firms to win work, Australia's Department of Industry, Innovation, Science, Research and Tertiary Education last year engaged economic advisory firm, Development Impacts, to undertake a project examining best practices by companies successfully supplying into the sector to determine how they meet the needs of project proponents.

Pia Turcinov, Development Impacts director, explained to Rigzone that it found there was more to the issue than obstacles such as a high Australian dollar, a lack of financial profile and Australia's skills shortage.

"They are huge hurdles for Australian companies, but there are other issues surrounding what the benchmarks are that local companies need to meet before they are considered… even in the tender stage," Turcinov, who also addressed the conference, said.

"Our work on this project identified 22 key factors companies need to focus on.

"Yes, price was a major factor, but other key factors were about quality, flexibility, design capabilities, QA systems, technical expertise, after sale service, and financial capabilities and risk profile.

"We looked at factors such as these and how the better performing companies compare and where they are outperforming against expectations."

Turcinov explained that suppliers needed to establish a clear capability beyond just a normal website and marketing brochure, and it was advisable for them to look at forming alliances with other local companies to build profile and capability.

In an election year, both at a federal and state level in WA, political parties in Australia have been prioritizing this issue.

WA's governing Liberal Party regularly produces an industry participation framework aimed at ensuring the local industry receives opportunity to participate in major resource projects.

The opposing Labor Party in WA has also shown its commitment by releasing a discussion paper outlining its openness to the issue.

At a federal level, the governing Labor Party is focusing on strengthening opportunities for the local industry through a proposed plan administering the issue.

Under the plan, major projects worth $519 million (AUD $500) million or more will be required to have an Australian industry participation plan identifying opportunities for local firms.

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Time to Look for Unconventional Gas in the Middle East

The most worrying problem of all in the Middle East and North Africa (MENA) region is also the most ironic. In a region with an estimated 1,496.2 trillion cubic feet (Tcf) of natural gas, according to the latest BP Statistical Review of World Energy, there appears to be scarce supplies of gas to the countries in the region mainly because of the rapidly growing population which is placing ever increasing demands on gas for electricity generation and water desalination.

The numbers mentioned above says half the truth, as the majority of reserves are hard to extract and requires advanced technologies, which means that the cost of extraction will be high.

In addition to the important conventional reserves, results from recent gas exploration and appraisal activities indicate that the region holds substantial resources of unconventional gas, especially tight gas and shale gas.

Regardless of the existing highly productive conventional gas fields and reserves in this region, shale gas and tight gas-related exploration and appraisal activities in several countries in the region have increased and are expected to pick up pace going forward, with the goal of identifying the potentials first, rather than proceeding to the development.

Algeria is taking the lead in this domain, and Algerian Energy Minister Youcef Yousfi revealed that he believes that his country's reserves of shale gas are equal to that of the United States. Algeria's state energy company, Sonatrach, has signed a cooperation agreement with Italian company Eni SpA, for the development of unconventional gas in Algeria, with a particular focus on shale gas.

"We have launched four studies to evaluate the potentials of shale gas and liquids, in partner with Eni, Talisman, Shell and Anadarko, and we are in discussion with other companies for similar projects. All these studies will go through a pilot project either in partnership or with our proper efforts," said Abdelhamid Zerguine, chief executive office of Sonatrach.

Sonatrach has also drilled first shale gas well using its own resources, Abdelhamid Zerguine said.

"Using our own efforts, we have finished the drilling of the first shale gas in the central part of the Sahara. The initial interpretation of the data of these wells showed that the potential of gas are similar to those basins [known] around the world. The well has completed, and we will be conducting a simulation test by end 2012. A second drilling is currently underway," he added.

In the neighboring country, Libya, technically recoverable shale gas is estimated at about 290 trillion cubic feet according to data from the U.S. Energy Information Administration.

"Gas has never been a priority for us, but it is now. We may have some of the most important shale gas deposits in the world," National Oil Co. Chairman Nuri Berruien said during a North Africa Gas Summit held in Vienna last year.

"Right now we are evaluating the reserves and talking to our partners," Berruien said. "The potential is definitely there."

In Egypt, because of the absence data of unconventional gas resources in the country, it has formed a committee composed of representatives from all government entities that can contribute to exploration of shale gas.

The committee is tasked with gathering all possible relevant data, including assessing what the country has in terms of shale gas, looking at reports and research conducted in other countries on a regional level, and looking at what producing countries have done to reach the stage of production.

It also collaborates with companies like Halliburton Co. and Schlumberger Ltd. to gather data related to the shale gas exploration. Local media reported that discussions over investments in unconventional resources are set to take place in early 2014. Authorities are also working on the terms and conditions of operations at shale gas fields, as the current conditions don't encourage investors to explore unconventional resources.

In Saudi Arabia, U.S. oilfield services company Baker Hughes estimates Saudi Arabian shale gas reserves at 645 Tcf, the fifth largest such reserve in the world. The country's conventional gas reserves are estimated to be around 279 Tcf.

Saudi Aramco has begun pilot projects using high-end technology to extract unconventional gas, including tight gas and shale gas. The first unconventional gas wells are planned for this year.

"Saudi Arabia's unconventional gas reserves resource base is large. The numbers are in the hundreds of Tcf, which are recoverable," Khalid Al-Falih, president and chief executive officer of Saudi Aramco said, cautioning: "Until we do the exploration and pilots, we will not be able to bank on them, so to speak."

Oman is also investigating exploration for shale gas, as the Sultanate looks to ease the gas squeeze holding back its industrial and petrochemical sectors.

"At the moment we are not drilling. It is just a study," said Khalifa Mubarak Al Hinai, advisor at the Ministry of Oil and Gas, according to the Times of Oman.

BP said that it is considering going ahead with a $20 billion (AED 73.45 billion) project to produce tight gas reservoirs deep under the Khazzan and Makarem fields in the north-central region. Negotiations are continuing.

The United Arab Emirates (UAE), instead, opted for the development of sour gas fields. It is currently developing the Shah Gas field in joint venture with Occidental Petroleum Corporation (Oxy). The $10 billion project is being developed by Alhosn Gas, a joint venture between Abu Dhabi National Oil Company and Oxy which holds a 40 -percent participating interest in a 30-year contract.

The field's high H2S content - 23 percent in the well fluid – means that in addition to key HSE design and implementation considerations, it will pose certain unique challenges due to the sheer scope of work to be done. The SGD project will also have a total of four trains – the largest in the world - for the massive Sulphur Recovery Units (SRU) that would process the 1 billion cubic feet per day of sour gas. The SRUs will have a capacity of 2500 T/D.

Kuwait is also tapping the development of the Jurassic field, and has signed a technical cooperation contract with Royal Dutch Shell plc.

While OPEC members are assessing their unconventional resources, with a particular focus on unconventional gas rather than unconventional oil, because of the abundance of conventional oil, Jordan - which suffers from the absence of hydrocarbon reserves - aims to extract 40,000 barrels of oil per day from its huge shale oil reserves by 2016 to meet the increasing local demand, said Bassam Gagish, chief executive of The Jordan Oil Shale Energy Company.

While countries in the region are evaluating their shale gas reserves, they don't expect to start the development of these wells any time soon, due to the absence of clear environmental legislation related to the exploration of these resources.

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Eni Strikes Again Offshore Angola

Eni has made its ninth oil discovery in Block 15/06, in deep water offshore Angola, increasing the resource base of the West Hub project. The discovery was made through the Vandumbu 1 well, located approximately 93 miles (150 kilometers) from the coast. The well was drilled at a water depth of 3,202 feet (976 meters) and reached a total depth of 13,474 feet (4,107 meters).

Additional drilling has been carried out from the Vandumbu 1 well in different direction (side track), Vandumbu 1 ST, that reached a depth of 11,417 feet (3,480 meters), finding a net oil (34 degree API) pay of 374 feet (114 meters), contained in Lower Miocene high quality sand. As suggested by data acquired, Eni estimates that Vandumbu 1 ST has a production capacity in excess of 5,000 barrel of oil per day.

Eni is operator of Block 15/06 with 35%. The other partners of the joint venture are SSI Fifteen Limited (25%), Sonangol (15%), Total (15%), Falcon Oil Holding Angola SA (5%) and Statoil Angola Block 15/06 (5%).

This discovery confirms Angola as one of the core countries in Eni's organic growth strategy. Eni has been present in the country since 1980 with a net production of 102,000 barrels per day in 2011.

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Fugro Chance, CODA Join Forces in Subsea Imagery

Fugro Chance Inc. and Coda Octopus Group Inc. (CODA) have entered into a Cooperation Agreement for two years to take advantage of Coda Octopus Echoscope; a patented 3D sonar technology. This relationship will give CODA early access to real-world requirements associated with Fugro Chance projects. Having access to the myriad of data acquired by Fugro will enable CODA to utilize the Echoscope in a variety of applications and challenges, thus maintaining a cutting edge in sonar technology. In return, Fugro will have the advantage of working with CODA to develop tailored solutions for their clients' subsea imagery deliverables.

Coda Echoscope Dual Frequency 3D Sonar is a unique sonar device using phased array technology. It generates over 16,000 beams simultaneously, producing instantaneous, three-dimensional sonar images of both moving and stationary objects and enabling extremely rapid reconnaissance and inspection.

Fugro Chance has proven field success in project time and cost savings as well as operational benefits from using this technology.

Fugro Chance Data Manager Tony Gray commented, "There is a world of possibilities with this 3D technology; be it installing platform legs subsea, seabed clearance surveys or even close-proximity subsea structure point cloud acquisition. Echoscope is a resourceful tool that can be used in subsea projects where time, risk and depth are all critical factors to visualization and measurement."

The two companies will work together on joint developments of new applications for meeting Fugro Chance requirements in data visualization and processing. In addition, Fugro Chance will gain market advantage from training opportunities provided by CODA as well as project support.

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Aker Wins Exxon Umbilicals Supply Deal

Norwegian oilfield services firm Aker Solutions announced Friday that it has won a deal with ExxonMobil for the supply of subsea umbilicals to the Erha North Phase 2 development, offshore Nigeria.

Erha North Phase 2 is an extension of the existing Erha subsea system and infrastructure, located approximately 60 miles off Nigeria in water depths of between 3,300 and 3950 feet.

The scope of the work includes the delivery of two dynamic and two static steel tube umbilicals of a total length of approximately 10 miles. The umbilicals will be delivered in 2014.

"We are pleased to extend our global footprint and support ExxonMobil in Nigeria. Aker Solutions provides cost effective and technically advanced subsea umbilicals worldwide and we look forward to execute another deepwater project," Tove Roskaft, head of Aker Solutions' umbilicals business area, commented in a statement.

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Drilling report, March 17

The drilling report was produced with data from the Texas Railroad Commission, from March 3 to 9. The following counties were searched: Anderson, Angelina, Camp, Cass, Cherokee, Dallas, Ellis, Freestone, Gregg, Harrison, Henderson, Houston, Kaufman, Leon, Limestone, Marion, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, San Augustine, Shelby, Smith, Upshur, Van Zandt and Wood. For information contact Business Editor Casey Murphy at cmurphy@tylerpaper.com or 903-596-6289.

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DOI: Shell Failed to Finalize Key Components of Alaska Program

Royal Dutch Shell plc's failure to finalize key components of its 2012 Alaska Arctic drilling program, including its oil spill containment system Arctic Challenger, led to Shell's failure in receiving needed permits to drill into oil-bearing zones in the Chukchi and Beaufort seas, according to the findings of a U.S. Department of Interior (DOI) review released Thursday.

Secretary of the Interior Ken Salazar called for a high-level, expedited review of Shell's program Jan. 8, including Shell's preparations for last year's drilling season and its maritime and emergency response operations – to identify the challenges Shell faced in its Arctic drilling plans and future lessons to be learned from that experience.

The review examined Shell's safety management system and the company's ability to meet the stringent standards set by the Department of the Interior for Arctic development. It focused on Shell's inability to obtain certification for the Arctic Challenger on a timely basis, the difficulty Shell encountered in deploying the vessel, and the marine transport issues Shell faced with the Noble Discoverer (mid-water drillship) and Kulluk drilling rigs, including the Kulluk's grounding offshore Kodiak Island, Alaska while being towed. Both rigs are en route to Asia for repairs.

Shell's failure to monitor contractor progress on key components of its Arctic drilling program, including the Arctic Challenger, was a pervasive theme in the review's findings. The contractor that Shell used to design and build the Arctic Challenger, had extensive experience working in the Gulf of Mexico, but ultimately, Shell ran into problems bringing the containment system online. The vessel failed to receive its U.S. Coast Guard certification, and the deployment of the system itself failed.

"Working in the Arctic requires thorough advanced planning and preparation, rigorous management focus, a close watch over contractors, and reliance on experienced, specialized operators who are familiar with the uniquely challenging conditions of the Alaska offshore," Salazar commented during a conference call Thursday with reporters.

Shell fell short in this area, Salazar noted, which contributed to many of the problems it faced, including the inability to deploy a functioning containment system, as well as the violation of air emissions requirements Shell encountered.

DOI Deputy Secretary David J. Hayes said the review confirmed the importance of strong coordination of among federal agencies in connection with permitting and exploration activities. This coordination has been an initiative through Executive Order 13580. Established in July 2011, the working group was created to coordinate efforts of federal agencies responsible for overseeing safe and responsible development of onshore and offshore energy in Alaska.

These agencies include the Bureau of Ocean Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE), the U.S. Coast Guard, the National Oceanic and Atmospheric Administration (NOAA), and the U.S. Environmental Protection Agency (EPA).

The review also reinforces the Obama administration's commitment to ensuring oil and gas exploration activities maintain safety at all levels, said BSEE Director James Watson.

"We will continue to maintain rigorous oversight of drilling and hold anyone operating in public waters to the highest environmental and safety standards."

Watson noted the administration looks forward to learning more from the findings of the Coast Guard's current investigation into the Kulluk grounding incident.

Shell should submit to DOI a comprehensive, integrated plan describing all phases of operation, from preparations through demobilization, when the company resumes exploratory drilling in Alaska's Arctic offshore region. This plan will go one step beyond the current recommendations for plan submissions, including not only details of drilling plans but for maritime operations as well.

The review also recommended Shell complete a full third party management system audit to confirm the capability of the company's management system, including oversight of key contractors, are tailored for Arctic operations, and that Shell has addressed the issues it faced in the 2012 drilling season.

Additionally, the review findings confirmed the necessity of an Arctic-specific model, and recommends continuing work on safety and environmental practices appropriate for the Arctic.

"We must recognize and account for the unique challenges of this region, which holds significant energy potential, but where issues like environmental and climate conditions, limited infrastructure, and the subsistence needs of North Slope communities demand specialized planning and consideration," said Principal Deputy Assistant Secretary for Land and Minerals Management Tommy Beaudreau, who led the review team.

The review, which involved the efforts of BSEE James Watson and staff, Alaska regional staff for BSEE and the BOEM, as well as input from NOAA and the EPA, which oversaw Shell's Alaska activity. The Coast Guard also provided technical assistance. Additionally, DOI officials met with Alaska state legislators, native Alaskan organizations, and environmental groups, as well as marine contractors and oil and gas companies.

When asked whether Shell's Alaska program highlighted any changes that needed to be made to the government process, Salazar noted government officials had learned a great deal from Shell's 2012 effort and still had a lot to learn.

"The Arctic is a difficult environment, and Shell is one of the most resource-capable companies in the world. Just because Shell encountered problems there doesn't mean that exploration shouldn't occur," Salazar commented, noting that 30 exploration wells have previously been drilled in both the Beaufort and Chukchi seas. "We allowed Shell to move forward cautiously with limited activity in the Arctic because Shell didn't meet the requisite permit requirements," Salazar said.

Hayes noted that Shell had been cooperative with the review process, and has acknowledged the issues it faced in terms of contractor timing with the Arctic Challenger.

"They put a lot of effort late into the game to get it certified, but not in time for the 2012 season."

Salazar said Shell should use its planned pause of its Alaska drilling plans for 2013 to learn the lessons from its 2012 drilling season. Hayes noted that Shell would use the time to conduct more testing of the Arctic Challenger to ensure all of its systems are in place so they will not be pressed for time the same way they were pressed for time for the 2012 season.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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Rosetta Buying Permian Basin Assets from Comstock for $768M

Rosetta Resources Inc. agreed to buy all of Comstock Resources Inc.'s oil and gas properties in the Reeves and Gaines counties of West Texas for $768 million, giving Rosetta exposure to the Permian Basin and a complement to its Eagle Ford properties.

"This transaction provides entry into the prolific Permian Basin with both existing production and strong growth potential...as well as prospective exploration targets," said Rosetta Chief Executive Jim Craddock.

Comstock's shares jumped 5.8% premarket to $16.88, while Rosetta's were inactive at $50.

The acquisition covers about 53,300 net acres. The Reeves County assets include about 40,200 net acres and 74 producing wells. Total current net production is about 3,300 barrels of oil equivalent per day, of which more than 73% is oil. Rosetta said it projects significant growth potential in the area and the company will be the operator of the majority of the Reeves County assets.

The Gaines County assets cover about 13,100 net acres, with multiple exploratory opportunities for the area, Rosetta said.

The deal is expected to close in mid-May, and Rosetta secured an additional $700 million of financing for the transaction.

Comstock said it plans to use the proceeds from the sale to reduce its outstanding debt and fund an increase to its 2013 drilling program in the Eagle Ford shale in South Texas. The company now forecasts spending $410 million in 2013 on drilling activities and $12 million in exploratory leasehold, for total capital spending of $422 million. Comstock plans to spend $312 million in Eagle Ford.

Last month, Rosetta said its fourth-quarter profit had risen 31% as revenue climbed, but results missed expectations. Also last month, its former chief executive, Randy Limbacher, stepped down and was replaced by Mr. Craddock, who had been Rosetta's senior vice president of drilling and production operations.

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Lundin Reports Dry Well in North Sea

Sweden's Lundin Petroleum reported Friday that its wildcat well 16/1-17, targeting the Jorvik prospect in the North Sea, has come up dry.

The well, located approximately 3 miles east of well 16/1-8 (the Edvard Grieg discovery well), was drilled with the objective of proving petroleum in Pre-Jurassic sandstone and conglomerate rocks.

Liquid samples acquired from the well did show mobile oil in a dense reservoir section. But despite core samples taken from this section that showed oil, Lundin said it has not been possible to establish an oil gradient and the well has been classified as dry.

Lundin, as operator, has a 50-percent working interest in production license PL338, where the Jorvik target is located. Partners include Wintershall Norge, with a 30-percent interest, and OMV, which has a 20-percent interest.

Well 16/1-17 was drilled by the Transocean Winner (DW semisub) rig, which will now proceed to production license 036 D where Marathon Oil Norge is the operator.