MWCC's First Non-Member Gets Permit Approval

- MWCC's First Non-Member Gets Permit Approval

Wednesday, September 07, 2011
Marine Well Containment Co.

Marine Well Containment Company (MWCC) announced that Petrobras America Inc. (PAI) is the first non-member to have cited MWCC's system to receive an approved drilling permit.

PAI contracts with MWCC for the right to cite the MWCC system in its permit application to the Bureau of Ocean Energy, Management, Regulation and Enforcement for a deepwater well in the U.S. Gulf of Mexico.

The agency approved the PAI application on September 2 to drill a development well at its Cascade field approximately 180 miles south of the Louisiana coast in water depth of 8,200 feet.

"MWCC is a not-for-profit, independent organization available to all deepwater U.S. Gulf of Mexico operators," said Chief Executive Officer Marty Massey. "Even if an operator is not a member of MWCC, our system can be made available on a well by well basis and cited in respective applications for permits to drill."

The MWCC member companies include Chevron, ConocoPhillips, ExxonMobil, Shell, BP, Apache, Anadarko, BHP Billiton, Statoil and Hess. These 10 companies operated approximately 70 percent of deepwater wells drilled in the U.S. Gulf of Mexico between 2007 through 2009.

All MWCC members have equal ownership, with each paying a proportional share of the system development and operating costs. System equipment and services are available to members and can be made available to non-members for use in the U.S. Gulf of Mexico.

An expanded containment system is on track for delivery in 2012. In addition to operating in water depths up to 10,000 feet, the system will have the capacity to capture up to 100,000 barrels of fluid and handle up to 200 million cubic feet of gas per day.

Oil & Gas Post

Promote Your Page Too
LINK

Det norske Submits First PDO as Field Operator

- Det norske Submits First PDO as Field Operator

Monday, September 05, 2011
Det norske Oljeselskap

Det norske will present a plan for development and operation (PDO) of Jette to the Minister of Petroleum and Energy Ola Borten Moe, Monday. The PDO will be submitted on behalf of the partners in the Jette Group, which in addition to Det norske includes Petoro, Dana Petroleum and Bridge Energy.

Erik Haugane, CEO of Det norske, said it is a big and important decision for the company to submit a PDO for Jette. "This is a small development relative to other North Sea-projects, but it is our first field development as operator. We believe it is best to start off with a small-scale development before moving on to bigger projects, like Draupne. In a few years, we could also become a significant operator of field developments off Norway."

Jette is a small field located in the North Sea, just east of the Jotun Field. Jette will be produced with two horizontal wells, tied back to the Jotun floating production storage and offloading vessel (FPSO). Jette is a very good example of what the government describes as time-critical resources.

"Even though Jette is a small development, it still represents value for the companies and the Norwegian society. Det norske believes that oil companies should also take on these projects," said Haugane

First oil in 2013

Jette contains about 14 million barrels of oil equivalents, based on a 30 percent recovery rate. Daily production the first year will be approximately 14 000 barrels, of which some 9 000 barrels will accrue to Det norske. Estimated development costs of Jette is approximately 2,5 billion NOK. Given the current oil price, Jette may generate gross revenues of 8 billion NOK. Operational costs are lower compared to typical operating costs of stand-alone developments and therefore enhancing the profitability of the development. Production startup is set to 1st quarter 2013.

Through a share issue last week, Det norske strengthened its equity ahead of developing Jette. Field development and operation will be led by Det norske in Trondheim, while daily monitoring of operations is carried out by ExxonMobil.

The partners in Jette are Det norske (63.3 percent, operator), Dana Petroleum (19.2 percent), Bridge Energy (6.0 percent) and Petoro (11.5 percent).

Oil & Gas Post

Promote Your Page Too
LINK

Brazil's Petrobras Expects First Oil from Franco Field in 2015

- Brazil's Petrobras Expects First Oil from Franco Field in 2015

Tuesday, August 23, 2011
Dow Jones Newswires
RIO DE JANEIRO
by Jeff Fick

Brazilian state-run energy giant Petroleo Brasileiro, or Petrobras, expects to produce its first oil from the Franco field in 2015, a key executive said Tuesday.

Franco was one of the areas obtained from Brazil's government as part of last year's capitalization of the company, which included a $70 billion share offer.

A floating production, storage and offloading vessel, or FPSO, will be installed at the field in 2015, said Jose Formigli, Petrobras's executive manager for pre-salt exploration and production.

"We've already concluded seismic [imaging] of the area where the first production system will be installed," Formigli said.

Franco is expected to produce an average of 13,000 barrels a day in 2015.

Copyright (c) 2011 Dow Jones & Company, Inc.

Oil & Gas Post

Promote Your Page Too
LINK

SOCO, Partners Tame First Flow from Te Giac Trang Field

- SOCO, Partners Tame First Flow from Te Giac Trang Field

Monday, August 22, 2011
SOCO International plc

SOCO announced the first flow of crude oil and wet gas from the Te Giac Trang Field ('TGT'), which occurred at 0655 local time in Vietnam today. The block is operated on behalf of SOCO and its Partners, PetroVietnam and PTT Exploration and Production Public Company Limited, by the Hoang Long Joint Operating Company ('HLJOC'), which was established in 1999.

The TGT (White Rhineoceros) Field, discovered in August 2005, was approved for the initial development by the Government of Vietnam in September 2009. The development is comprised of a Floating, Production, Storage and Offloading vessel ('FPSO'), two Well Head Platforms (H1 and H4 areas), and a subsea pipeline system to transport hydrocarbons, gas export, gas lift and water for injection.

Crude oil from the TGT Field is transported via a subsea pipeline system to the FPSO 'Armada TGT 1', which has a name plate processing capacity of 55,000 barrels of oil per day ('BOPD'), where it is processed, stored and exported via tankers to regional oil refineries. Gas will be transported through a pipeline to the nearby Bach Ho Facilities for processing and transportation to shore via the existing pipeline infrastructure for further distribution to meet domestic demand. TGT oil output is expected to plateau at approximately 55,000 BOPD and gas production will be approximately 30 million cubic feet per day.

The development of the TGT Field marks a successful investment co-operation milestone in the Vietnam oil and gas industry with the delivery of production within two years of approval.

In addition to starting first production from the TGT Field H1 area, HLJOC continues drilling production wells in the H4 area of the TGT Field and fabricating Platform Topsides in preparation for its petroleum production start-up in August 2012.

Ed Story, President and Chief Executive of SOCO, commented, "We are very pleased to announce first oil from the TGT Field in Vietnam, a key milestone for the Company demonstrating our ability to see our exploration successes through to the production stage. The project always had an ambitious delivery target and we are pleased to have achieved this.

"Our strong partnerships have allowed this significant event at the TGT Field to be realized and we now look forward to targeting further exploration and development success, both in Vietnam and in Africa."

Oil & Gas Post

Promote Your Page Too
LINK

BOEMRE to Hold First GOM Lease Sale since Spill

- BOEMRE to Hold First GOM Lease Sale since Spill

Friday, August 19, 2011
BOEMRE

Secretary of the Interior Ken Salazar and Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) Director Michael R. Bromwich announced that BOEMRE will hold the first oil and natural gas lease sale in the Gulf of Mexico since the Deepwater Horizon explosion and oil spill. Consistent with steps President Obama announced in May 2011 to expand domestic oil and gas production safely and responsibly, the proposed Western Gulf of Mexico Lease Sale 218 is scheduled to be held in New Orleans on December 14, 2011. The sale will include all available unleased areas in the Western Gulf Planning Area offshore Texas.

"This sale is an important step toward a secure energy future that includes safe, environmentally-sound development of our domestic energy resources," Secretary Salazar said. "Since Deepwater Horizon, we have strengthened oversight at every stage of the oil and gas development process, including deepwater drilling safety, subsea blowout containment, and spill response capability. Exploration and development of our Western Gulf's vital energy resources will continue to help power our nation and drive our economy."

"BOEMRE has taken aggressive steps to renew our commitment to the responsible stewardship of the U.S. Outer Continental Shelf," said Director Bromwich. "The decision to hold this sale was made after careful analysis of the best scientific information available and consideration of all public comments received."

The proposed lease sale encompasses about 3,900 un-leased blocks covering approximately 20.6 million acres. The blocks are located from 9 to about 250 miles offshore, in water depths ranging from 16 to more than 10,975 feet (5 to 3,346 meters). BOEMRE estimates the proposed lease sale could result in the production of 222 to 423 million barrels of oil and 1.49 to 2.65 trillion cubic feet of natural gas.

As part of the Administration's commitment to provide incentives for diligent development, and to ensure receipt of fair market value for the lease rights sold, BOEMRE proposes to increase the minimum bid amount for blocks in water depths of 1,312 feet (400 meters) and greater to $100 per acre. The minimum bid for those water depths in previous sales was $37.50 per acre.

This change is based on a rigorous historical analysis of the last 15 years of lease sales in the Gulf of Mexico. The analysis, adjusted for energy prices at time of each sale, demonstrates that leases that received high bids of less than $100 per acre have experienced virtually no exploration and development activities. In light of this analysis, BOEMRE has concluded that the increase will have little to no adverse impact on the timing or magnitude of production from tracts offered in this sale. Raising the minimum bid will discourage companies from purchasing leases they are unlikely to explore in the near term.

"BOEMRE is proposing this increase in an effort to ensure that areas with the greatest resource potential are developed, and to decrease the amount of leased acreage that is warehoused and goes unexplored," Director Bromwich said. "The change in terms will better ensure that the nation's resources are being developed in a timely manner."

The minimum bid amount for leases in the much more heavily explored and produced shallower water depths will remain at $25 per acre.

The lease sale will include environmental stipulations requiring that operators protect biologically sensitive features, as well as marine mammals and sea turtles. These stipulations will require trained observers to ensure compliance and restrict operations when conditions warrant.

Lease Sale 218 is the last remaining Western Gulf Planning Area sale scheduled in the 2007 – 2012 Outer Continental Shelf Oil and Natural Gas Leasing Program. The terms and conditions outlined in the package are not final. Different terms and conditions may be employed in the Final Notice of Sale, which will be published at least 30 days before the sale.

Oil & Gas Post

Promote Your Page Too
LINK

Countdown to First Gas at Gajah Baru

- Countdown to First Gas at Gajah Baru

Friday, August 19, 2011
Rigzone Staff
by Jaime Kammerzell

Premier Oil is set to bring its Gajah Baru natural gas field online in October 2011. The field is in Block A in the West Natuna Sea, Indonesia, in 269 feet (ft) of water, which is near Premier's West Natuna Gas Project.

According to Premier Oil, gas from West Natuna is sold to Singapore under a 27 year gas sales contract in conjunction with other production sharing contracts through the West Natuna Transportation System gas pipeline. When signed in 1999, contract deliveries were expected to be 325 MMscf/d of gas (block A share 120 MMscf/d), but volumes exceed these levels today.

Premier signed separate gas sales agreements with SembCorp Gas, Indonesia's Perusahaan Listrik Negara and Universal Batam Energy for contract gas sales volume of up to 145 Bbtu/d.

Premier Oil operates the field with 28.67 percent interest with co-owners Kufpec holding 33.33 percent interest, Amerada Hess with 23 percent interest and Petronas with 15 percent interest.

Premier drilled the Gajah Baru-1 discovery well in 2000. The well tested to have proven gas columns in eight separate reservoir sands in the Arang formation. According to Premier, the well flowed 40 MMscf/d during testing.

Transocean's Trident XVII jackup drilled the Gajah Baru-1 slim hole well to 5,290 ft.

Trident XVII

In September 2004, Premier drilled the appraisal well, Gajah Baru-2, to 9,010 ft and proved the presence of hydrocarbon reserves in stacked Miocene reservoirs of the Arang formation and the Oligocene sands of the Gabus formation. Premier drilled the top section of the well to 2,214 ft with 13 3/8" casing using a casing-while-drilling technique, establishing a new world record for this method at the time.

Based on appraisal drilling conducted in October 2004, the operator estimates that the field contains 325 Bcf (54 MMboe) of gas.

The field is expected to produce 100 MMcm/d.

Production Plan

Premier Oil received project sanction in 2010. The operator planned to develop the field with subsea wells tied back to a central processing platform and a wellhead platform connected by a bridge.

The wellhead platform was installed in 3Q 2010 and weighs about 900 tons with a jacket weight of about 1,400 tons.

Topsides construction for the central processing platform, which weighs 8,200-tonnes, was completed in June 2011, and left the SMOE fabrication yard in Batam, Indonesia, later that month. Together with the jacket, which weighs about 4,700 tons, the central processing platform includes compression, separation, glycol regeneration, gas metering, mechanical refrigeration, utilities and living quarters for 60 men.

Saipem installed the central processing platform over a jacket that Japan's Nippon Steel in Indonesia built.

Wellhead Platform

The West Callisto jackup is drilling 12-14 exploration and appraisal wells before the end of the year.

West Callisto

Premier will export produced gas through a 16-inch pipeline 2 miles to the onshore Semgas facility in Singapore. The pipeline rests 262 ft under the water's surface.
Contracts

In May 2009, while Premier waited for project approval, the operator awarded several contracts. The first of which went to Saipem and SMOE Indonesia, who received a $430 million contract for the engineering and construction of a central processing platform, a wellhead platform and a subsea gas pipeline.

PT SMOE Indonesia's portion of the contract entails part procurement, construction engineering, construction, hook-up and commissioning of the two platforms, while PT Saipem Indonesia's scope of work, worth about $280 million, covers engineering design, procurement, transportation and installation of the platforms and the subsea pipeline.

The central processing platform will be installed using the floatover method, while other platform facilities and pipeline will be installed using Saipem's Castoro Otto derrick/lay barge. The marine activities will be completed in 4Q 2011.

Castoro Otto

Premier also awarded Nippon Steel Batam a contract to construct the wellhead deck, piles and conductors. The company will also install the central processing platform's jacket and piles.

In August 2009, Premier contracted Process Group to supply a monoethylene glycol regeneration unit for the central processing platform and to supply a produced water treatment unit for the platform, which will be used to separate oil from the produced water. It will be able to treat 2,400 b/d of produced water.

In February 2010, Premier awarded Hutchinson Offshore a contract to provide leg mating and deck support facilities.

Oil & Gas Post

Promote Your Page Too
LINK

Anadarko Executive: Drilling First Deep-Water Well Off Liberia

- Anadarko Executive: Drilling First Deep-Water Well Off Liberia

Thursday, August 18, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Anadarko plans an aggressive deep-water exploration campaign worldwide over the next year and a half, the head of the company's exploration unit said Wednesday.

"The inventory of opportunities we have is better than it's ever been," Bob Daniels, Anadarko's senior vice president of Worldwide Exploration, said during a speech webcast from an investor conference in Denver. "We will continue with a very aggressive exploration program around the world."

The Houston company's success in Ghana, where it last year brought the vast Jubilee discovery into production, has spread into neighboring West African nations, he said. In addition to offshore exploration in Sierra Leone and the Ivory Coast, Anadarko is drilling Liberia's first deep-water well at the company's Montserrado prospect.

Judging from seismic data and other geologic factors, the Montserrado prospect "is a look-alike" to the Jubilee discovery, Daniels said.

Jubilee is estimated to hold the equivalent of between 600 million and 1.5 billion barrels of oil.

In all, Anadarko plans 15 deep-water exploration and appraisal wells in West African waters, Daniels said.

In East Africa, where Anadarko has already made a huge natural gas discovery off Mozambique, the company holds some 14 million acres. Daniels said Anadarko will bring a second rig to Mozambique in the fourth quarter and anticipates drilling prospects off Kenya, where Anadarko has leased "most of the deep water," next year.

Deep-water exploration is also slated to begin off New Zealand next year, he said.

"In the deep-water Gulf of Mexico, we have an inventory of discoveries and we have a very, very deep portfolio of exploration wells to drill," Daniels said.

The second-largest acreage holder in the U.S. Gulf of Mexico, Anadarko plans five deep-water exploration wells there this year and between six and eight exploration and appraisal wells next year.

In the last three weeks Anadarko has obtained three drilling permits from U.S. regulators, he said.

"That's very good progress in that we now have some confidence that when we apply for a permit we know about how long its going to take," he said. "That allows us to then put rig contracts in place."

Permits have been difficult to come by since last year's deadly Deepwater Horizon disaster. Anadarko was a minority owner of BP's doomed well, which blew out and caused the worst offshore oil spill in U.S. history.

Anadarko said last month that it has agreed to jointly develop its Lucius field in the Gulf with ExxonMobil, which has its own big discoveries a few miles away. Lucius is believed to hold 300 million barrels of high-quality crude and Daniels said he expects the project to be sanctioned by the end of this year with first production planned for 2014.

Copyright (c) 2011 Dow Jones & Company, Inc.

Oil & Gas Post

Promote Your Page Too
LINK

Petrobras Pumps First Oil at Marlim Sul Field

- Petrobras Pumps First Oil at Marlim Sul Field

Wednesday, August 17, 2011
Petrobras

Petrobras announced that semisubmersible platform P-56 began production on August 15, at Marlim Sul field, in Campos Basin (RJ). The unit began production through well 7-MLS-163HPRJS, which has a potential of approximately 16,000 barrels per day.

Installed at a water depth of 1,670 meters, the platform is designed to process up to 100 thousand barrels of oil per day when it reaches maximum capacity, expected to take place in the first quarter of 2012. Besides heavy oil of 18º API, P-56 will have the capacity to process and treat up to 6 million m³ per day of natural gas.

P-56 will be interconnected to 21 wells, of which 10 will be producers and 11 water injectors. The produced oil will be sent through oil pipeline to platform P-38, which is a FSO (floating storage and offloading vessel) type, located 20 km from the Platform. Then, the oil will be transferred to shuttle tankers and the natural gas will be delivered through gas pipeline to the Cabiúnas terminal.

P-56 is 125m long, 110m wide, 137m tall and has a total weight of more than 54 thousand tons. Construction of the integrated modules (topside) of P-56 reached a high rate of local content. The hull was built entirely in Brazil, which demonstrates the capacity of the local manufacturing sector to meet the orders of Petrobras.

Oil & Gas Post

Promote Your Page Too
LINK

First Subsea Scores Chevron Contract for Jack/St. Malo Facility

- First Subsea Scores Chevron Contract for Jack/St. Malo Facility

Thursday, August 11, 2011
First Subsea Ltd.

First Subsea has been awarded a contract by Chevron U.S.A. Inc. to supply the mooring connectors for the Jack/St. Malo semisubmersible hub production facility in the Jack/St. Malo fields located approximately 280 miles south of New Orleans, Louisiana, in water depths of 2,133 m (7,042 feet) in the Gulf of Mexico.

The semisubmersible, floating production unit (FPU) will be moored by 16 Ballgrab, ball and taper, mooring connectors attached to polyester mooring lines in a 4x4 arrangement. The Ballgrab Series III male connectors will be the largest produced so far with an un-corroded 2,599mT (25,491kN) MBL, and the first to comply with the new ABS Mooring Guide 2009.

The Ballgrab connector comprises a male connector and female receptacle. The female receptacle will be installed subsea with the mooring system's suction piles, mounted on docking porches. When the FPU is in position, the male connector, attached to the mooring line, is lowered from the surface into the female receptacle to complete the mooring installation. The process is then repeated until all 16 mooring lines are connected.

"We are delighted to have been awarded the Jack & St Malo FPU mooring connector contract," said Brian Green, general manager, First Subsea Ltd. "The Ballgrab mooring connector provides an efficient method of deploying deepwater mooring lines. For the Jack & St Malo connectors, we will be drawing on our world leading research into large scale forgings to optimize mooring performance."

Oil & Gas Post

Promote Your Page Too
LINK

First Subsea Names Global Sales, Business Development Manager

- First Subsea Names Global Sales, Business Development Manager

Tuesday, August 09, 2011
First Subsea Ltd.

First Subsea has appointed John Shaw as global sales and business development manager. Formerly head of Engineered Products Group at Trelleborg Offshore, he will be responsible for developing First Subsea's innovative ball and taper connector business worldwide.

In addition to the Ballgrab range of subsea mooring connectors, ball and taper has been successfully used for pipeline recovery and decommissioning tools, ROV and diverless bend stiffener connectors for risers and umbilicals, pipeline repair, hose connectors, heavy lift and buoy mooring and retrieval applications.

A Fellow of the Institute of Mechanical Engineers, Mr. Shaw is no stranger to the connector technology. At Trelleborg Offshore, he worked with First Subsea on the development of the diverless bend stiffener connector. "The simplicity of the ball and taper connection, and its powerful multi-point grip, makes it a very flexible solution to offshore connections in many demanding applications. My role will be to work with clients to develop existing and new applications for the ball and taper connector," he said.

First Subsea has successfully developed the ball and taper connector technology for drilling applications both onshore and offshore. One of this year's OTC Spotlight on Technology Awards included Canrig Drilling Technology's SureGrip Automated Casing Running Tool featuring the ball and taper gripping mechanism for handling drill piping.

"The ease of ball and taper connection makes it suitable for any application involving gripping, pulling and holding connections under load. John Shaw's experience will allow us to consolidate and improve our current product range, as well as developing opportunities for the connector in new markets," commented Brian Green, general manager, First Subsea Ltd.

Oil & Gas Post

Promote Your Page Too
LINK

Range Successfully Drills First Development Well in Trinidad

- Range Successfully Drills First Development Well in Trinidad

Monday, August 08, 2011
Range Resources Ltd.

Range announced that in the two months since completing its Trinidad acquisition, the Company has successfully drilled its first development well on the Morne Diablo Block.

As part of the initial 21 well drilling program, the MD 247 well was drilled to a total depth of approximately 900 ft using the Company's own drilling rig and personnel. Despite the shallow depth, open hole logs indicate the presence of roughly 145 ft. of net oil pay in the shallow Forest Formation, an established producing horizon on the block. Casing is currently being run in the well in preparation for production testing next week.

Added Peter Landau, Range's Executive Director, "The successful drilling of the MD 247 well indicates that Range's aggressive program to increase production and cash flow in Trinidad is on track and the first pay zone size has exceeded expectations. As previously announced, we will be adding a second and third rig to the remaining 20 well 2011 drilling program in order to begin exploitation of deeper producing reservoirs. The MD 247 well is only the beginning for us in Trinidad, but represents an important milestone for Range as our first internationally operated well, drilled and completed by the Company's own operations team using our own equipment."

The Company looks forward to keeping our shareholders updated as our drilling program continues in Trinidad, Georgia, Texas, and Puntland, in what will be an exciting period for Range with wells being drilled on all four the Company's assets in the coming months.

Oil & Gas Post

Promote Your Page Too
LINK

First Solar Misses Q2 Estimates

- First Solar Misses Q2 Estimates



Aug 4, 2011

First Solar (NASDAQ:FSLR) reported adjusted Q2 EPS of $0.70, missing analyst estimates of $0.92. Revenues for the quarter fell 9.4% to $533 million, less than consensus estimates of $583.42 million.

Rob Gillette, CEO of First Solar said, "First Solar continued to execute in the quarter despite a challenging European market, and our 2011 outlook remains solid due to our differentiated and resilient business model. We expect stronger performance in the second half of 2011 as we build projects from our systems pipeline, develop promising new markets, execute our cost reduction roadmaps and continue to improve module efficiencies."

First Solar (NASDAQ:FSLR) has a potential upside of 42.2% based on a current price of $107.94 and an average consensus analyst price target of $153.5.

Oil & Gas Post

Promote Your Page Too
LINK

Statoil Wraps Up First Phase at Gudrun Platform

- Statoil Wraps Up First Phase at Gudrun Platform

Wednesday, August 03, 2011
Statoil

The steel support structure for the Gudrun platform is now in place on the North Sea field, completing the first phase of the extensive installation work being carried out there.

"The entire operation has been carried out according to plan and in a secure manner," reported Anders Opedal, senior vice president for projects in Statoil's Technology, Projects and Drilling business area.

"We've passed an important milestone for coming on stream at the right time and to budget. With the jacket solidly positioned on the seabed, we'll be able to start drilling in the fourth quarter as planned."

Installation of the steel structure began on July 24, and the job of attaching it to the seabed was completed on August 2 when the last of 12 60-meter piles was driven home.

Saipem 7000, the world's second-largest crane vessel, has been used to carry out the installation work on Gudrun.

Weighing some 7,000 tonnes all told, the traditional jacket comprises two main structures of almost 2,300 tonnes each, tied together by six horizontal frames and various bracings.

Important contribution

"Gudrun is the first of a number of new installations in an area of the Norwegian North Sea which is both highly interesting and mature," observes Ivar Aasheim, senior vice president for field development in the Development and Production Norway business area.

"By exploiting existing infrastructure for processing and transport, we're ensuring production from new fields. Gudrun will also make an important contribution to maintaining high production levels going forward."

The next development milestone is the start of pre-drilling production wells on the field. These will be tied back to the platform for partial processing and oil and gas export.

Final processing of Gudrun's output will take place on Sleipner A, with the gas piped to the adjacent Sleipner T platform for carbon dioxide removal.

In addition, electricity to operate the Gudrun installation once it comes on stream in two years' time will be supplied from Sleipner A.

Gudrun ranks as one of Statoil's largest development projects on the Norwegian continental shelf, and contains some 127 million barrels of oil equivalent.

Oil & Gas Post

Promote Your Page Too
LINK

Pemex to Award Its First Incentive Contracts Aug 18

- Pemex to Award Its First Incentive Contracts Aug 18

Friday, July 29, 2011
Dow Jones Newswires
MEXICO CITY
by Laurence Iliff

Mexico's state-owned oil company Petroleos Mexicanos, or Pemex, said Friday it has set Aug. 18 as the date for the final awarding of its first incentive-based contracts allowed under a 2008 energy reform.

Pemex's first tender under the new contract mechanism is for six mature fields in three groupings in its southern region. Pemex said in a presentation on its website that 27 companies have participated in the tender process for the Magallanes, Santuario and Carrizo drilling areas.

Pemex hopes to use the flexible contracts, which pay bonuses for production above a certain level rather than a set per-barrel rate, to draw the best technology to reactivate about 40 mature fields in total. The flexible contracts will later be used to try and draw oil majors to the deep waters of the Gulf of Mexico, where Pemex has no production.

Under Mexican law, Pemex can't engage in shared-risk contracts, which is common in deep-water projects, and can't pay contractors with oil.

Carlos Morales, head of Pemex's exploration and production division, said during a conference call Friday that the re-opening of mature fields with new technology has great potential to compensate for the natural decline at other fields such as the super-giant Cantarell offshore complex.

Cantarell has fallen from a peak of about 2 million barrels a day in 2004 to about 460,000 barrels a day, according to Pemex figures. Morales said Cantarell has stabilized and will have significant production levels for a prolonged period of time.

Overall crude oil production in the second-quarter of this year was 2.558 million barrels a day on average, compared with the 2.578 million barrels a day in second-quarter 2010, Pemex said.

Pemex recorded a net profit in the most recent quarter of $769 million versus a net loss of $1.7 billion in the year-ago period. Total sales rose 25% compared to $33.22 billion, mostly on higher crude-oil prices. Cash flow as measured by earnings before interest, taxes, depreciation and amortization, or Ebitda, rose 31% to $24.1 billion, Pemex said.

Ignacio Quesada, director of corporate finances, said oil prices were affected by worries of availability due to events in the Middle East, among other factors, and that prices remained volatile along with other commodities.

Inline with the oil-price increase, Quesada added, Pemex had to pay higher prices for imported gasoline, which it sells at subsidized rates.

The oil monopoly, which funds about one-third of the federal budget, paid $18.6 billion in taxes and duties in the second-quarter, a 43% rise over the second-quarter of 2010.

Pemex said the economic impact of external and structural effects in the first half of the year included $1.2 billion for subsidies to liquefied petroleum gas sales, $900 million on price losses for gasoline imports, and $4.2 billion in labor obligations.

Copyright (c) 2011 Dow Jones & Company, Inc.

Oil & Gas Post

Promote Your Page Too

EPA Proposes First Federal Air Standards for 'Fracked' Wells

- EPA Proposes First Federal Air Standards for 'Fracked' Wells

Thursday, July 28, 2011
Dow Jones Newswires
WASHINGTON
by Tennille Tracy

The Obama administration has proposed the first national air standards for wells that are drilled using a controversial practice known as hydraulic fracturing.

The Environmental Protection Agency announced Thursday it was proposing new rules to reduce the amount of air toxins and smog-forming gases that are released into the air when oil and natural gas is produced.

The rules are expected to reduce cancer risks and help reduce ozone levels in areas where oil and natural-gas production occurs, the EPA said. The standards should also lead to lower emissions of methane, a greenhouse gas that is more than 20 times as potent as carbon dioxide.

A lot of the emissions the EPA has targeted escape into the air when natural-gas wells, drilled using hydraulic fracturing, or fracking, are being prepared for production.

The EPA is proposing to reduce the emissions by requiring the use of special equipment to separate oil and gas from a mix of fracking fluids and water that flows to the surface during one stage of well completion.

Certain states, such as Wyoming and Colorado, already require the use of this equipment.

The EPA says these proposed standards will eventually save the oil and gas industry about $30 million a year. That's because the standards will force companies to collect the hydrocarbons, which they can then sell.

Hydraulic fracturing already receives a lot of scrutiny from lawmakers, regulators and environmental groups because of its possible impacts on drinking water.

The proposed rules announced Thursday would apply to more than 25,000 wells a year, as well as to storage tanks and other pieces of equipment used by the oil and gas industry.

The EPA estimates the proposed rules will reduce smog-forming volatile organic compounds emitted by the oil and gas industry by 25%. They should also reduce methane emissions by 26% and air toxins by nearly 30%.

The EPA undertook this new rule-making after a pair of environmental groups successfully sued the agency to update clean-air standards for the oil and natural-gas industry. The agency is under a court-ordered deadline to finalize the rule by February.

"We are seeing oil and gas development take a tremendous toll on clean air," said Jeremy Nichols, director of the climate and energy program for Wild Earth Guardians. "Our health and environmental safeguards are woefully outdated."

The American Petroleum Institute, a group representing the oil and gas industry, asked the EPA to postpone the finalization of the rules by six months.

"API will review these proposed rules to ensure that they don't inadvertently create unsafe operating conditions, are cost effective and truly provide additional public health benefits," said Howard Feldman, API's director of scientific and regulatory policy.

Copyright (c) 2011 Dow Jones & Company, Inc.

Oil & Gas Post

Promote Your Page Too
LINK

OGX Finishes Drilling First Campos HZ Well

- OGX Finishes Drilling First Campos HZ Well

Friday, July 15, 2011
OGX S.A.

OGX announced the conclusion of drilling at the horizontal well 9-OGX-39HP-RJS (Pipeline Horizontal) and as expected identified very good reservoir conditions through a drill-stem test (DST). The well is located in block BM-C-41 in the Campos Basin.

"This was the third horizontal well test that yielded important results, confirming the quality of the accumulations discovered thus far and that are being appraised. We are continuing to move rapidly towards production," said Paulo Mendonça, General Executive Officer and Exploration Officer for OGX.

The OGX-39 well was horizontally drilled for more than 1,000 meters into the carbonate reservoirs of the Albian section of the Pipeline accumulation, which was originally discovered by the 1-OGX-2A-RJS well in November 2009, and uncovered new material information regarding the development of this area. The results from the drilling of the OGX-39 well demonstrated a high correlation with other wells in the Albian section, including calcarenites with excellent porosity with dolomitized and naturally fractured sections, and confirmed the extension of the Pipeline accumulation.

Following the conclusion of the drilling process, a DST was performed which indicated a production capacity of around 10,000 barrels of oil per day with an API gravity of approximately 19°. The process of selective acidification was used in six well intervals, which enabled better stimulation of the 1,000 meter horizontal well extension, thereby maximizing the oil flow.

Oil & Gas Post

Promote Your Page Too
LINK

Beach Begins Gas Flow at AU's First Shale Well

- Beach Begins Gas Flow at AU's First Shale Well

Tuesday, July 12, 2011
Beach Energy Ltd.

A significant gas flow of up to 2 million standard cubic feet per day (MMscf/d) has been achieved from Beach's Holdfast-1 exploratory shale gas well in the Cooper Basin. Holdfast-1, the first well drilled to examine the shale gas potential of the thick Roseneath-Epsilon-Murteree shale sequence in the Cooper Basin, is a vertical data gathering well that was recently flow stimulated in seven stages.

Hot water, steam and low levels of gas started to flow from the well on 1 July upon the commencement of post-stimulation clean-up activities. Late on Friday 8 July the flow was diverted through on-site separation equipment to more reliably measure the gas and stimulation fluid rates. With separation of the gas from the returning stimulation fluid the gas flare was successfully ignited. The gas flow rates, now measured, have remained steady at around 1.8 MMscf/d.

Beach regards the flow rates as significant, given the potential for higher flow rates from future horizontal wells. Follow up wells are planned to be drilled to target the optimal producing zone identified by the extensive coring, stimulation and testing program which has been undertaken by Beach in the Nappamerri Trough.

Beach Managing Director, Reg Nelson, said, "We are delighted and excited by this initial flow rate from Holdfast-1. So far the results give us confidence that these shale target zones, which underlie the conventional oil and gas bearing formations in the Cooper Basin, will significantly increase the natural gas potential of this area. It is still early days but this flow rate looks to be very significant."

Mr. Nelson added, "While these results are preliminary at this stage, it does suggest that significantly larger flow rates may be achievable in an optimally designed, pilot horizontal well. Holdfast-1 was deliberately designed to allow us to experiment with different stimulation techniques and to test different zones within a thick sequence of shales and other lithologies to determine which approach could be applied for the best results when designing a pilot production well."

Beach previously reported the flow stimulation of the Holdfast-1 well had been completed successfully with the various selected target zones fracturing vertically, in line with expectations. The vertical nature of the induced fracturing augurs well for future horizontal production wells.

A variety of well perforation techniques, fluid viscosity and proppant sizes was used in the stimulation of Holdfast-1 to provide a range of information on the response and performance of the different shale and tight rock zones intersected in the Permian aged section of the well. This approach is intended to identify which techniques are best suited to the pilot production program set down for 2012. This program will consist of two horizontal wells, one at each location.

The flow stimulation of Holdfast-1 was undertaken in seven stages, targeting the primary target zones of the Roseneath Shale (two stages), the Epsilon Formation (three stages) and the Murteree Shale (one stage), as well as a deeper secondary zone, the Patchawarra Formation (one stage).

Mr. Nelson said, "While we are greatly excited by the results from the Holdfast-1 well to date, we are not surprised by them. Beach has applied an extremely thorough and detailed technical approach over the past few years to its shale gas research, which identified the Cooper Basin, and more particularly the Nappamerri Trough, as one of the most prospective shale gas provinces in Australia. Beach has been a pioneer of shale gas exploration in Australia and is now best placed to lead the development of the shale gas industry through its accumulated expertise, its acknowledged competence as an operator and the fact that the Cooper Basin has well established infrastructure in place to assist in commercialization of this opportunity."

Participants in PEL 218 (Permian JV) are:

• Beach (Operator) 90%
• Adelaide Energy Ltd 10%

The Cooper Basin is the most prolific onshore petroleum province in Australia, having produced approximately 6 Tcf of gas to date, and is ideally situated as it has the necessary infrastructure for the delivery of oil and gas to the Eastern Australian markets. Within the Cooper Basin, Beach currently holds interests of approximately 20% of the SACB JV (Santos operated), this includes infrastructure such as the Moomba production facility, approximately 23% of the SWQ JV (Santos operated) as well as various oil interests of between 40-75% on the Western Flank of the Cooper Basin.

Oil & Gas Post

Promote Your Page Too
LINK

Eni Flows First Oil from GOM Appaloosa Field

- Eni Flows First Oil from GOM Appaloosa Field

Wednesday, July 06, 2011
Eni S.p.A.

Eni has started oil production from the Appaloosa field, located in the US Gulf of Mexico deepwater, 60 miles offshore the Louisiana coast southwest of New Orleans, in 2500 feet (approximately 760 meters) of water depth.

The producing well is located within the MC 459 Federal Unit (comprising blocks MC 459, 460 and portions of MC 503 and 504). Eni holds a 100% working interest in the field.

Appaloosa production commenced on June 21, 2011 through a subsea development and a twenty-mile long flow line tied back to the Corral Platform (operated by Eni). The well is presently flowing at a rate of approximately 7,000 barrels of oil equivalent per day. This is the second Eni field producing on the Corral Platform, which in aggregate is now processing 46,600 gross barrels of oil equivalent per day (33,000 net to Eni).

This development, the second start-up this year for Eni in the US following the Nikaitchuq field start up in Alaska, further strengthens Eni's role as an operator and enhances Eni's position as one of the top producers in the Gulf of Mexico.

In the US, Eni owns lease interests in 333 blocks in the Gulf of Mexico and in 411 leases in the Barnett gas shales onshore Texas, in partnership with Quicksilver. In addition, Eni owns interests in 140 leases in Alaska, between offshore and the North Slope, where it is currently operating the Nikaitchuq oil project.

Eni's total daily net production in the US is in excess of 100,000 barrels of oil equivalent (60% of which is operated).

Oil & Gas Post

Promote Your Page Too
LINK

UBS Up Target Price For First Solar to $170, Reiterates Buy

- UBS Up Target Price For First Solar to $170, Reiterates Buy



Jul 1, 2011

UBS increased its price target for First Solar (NASDAQ:FSLR) to $170 from $165 today and reiterated its buy rating on the stock.

The move comes after First Solar received conditional loan guarantees yesterday worth $4.5 billion from the Department of Energy to support three large solar panel projects in California.

Shares of First Solar are trading up 0.31% at $132.68.

First Solar has a potential upside of 14.3% based on a current price of $132.68 and an average consensus analyst price target of $151.63.

Oil & Gas Post

Promote Your Page Too
LINK

First Solar Wins $4.5 Billion in Conditional Loan Guarantees from the DoE

- First Solar Wins $4.5 Billion in Conditional Loan Guarantees from the DoE



Jun 30, 2011

First Solar Inc (NASDAQ:FSLR) is trading up big today after it was reported that the world's largest manufacturer of thin-film solar modules had won $4.5 billion in conditional loan guarantees from the Department of Energy for three California projects.

The company's Topaz and Desert Sunlight projects, which will have 550 megawatts of capacity each, and its 230-megawatt Solar Ranch project, were each offered low-cost financing needed for construction to commence, the agency said today in an e-mailed statement.

The agency must distribute all of the funds authorized for the loan guarantee program before it expires at the end of September. The agency has offered conditional loans or loan guarantees for 40 clean energy products totaling $38 billion, including $16 billion for solar energy.

First Solar said the construction projects approved today will add 1,400 jobs and that all of the 20 million plus cadmium telluride glass panels used in the projects will be manufactured at its plants in Ohio and in Arizona.

Shares of First Solar are trading up 6.3% at $137.57.

Oil & Gas Post

Promote Your Page Too
LINK