Cairn suspends drilling offshore Greenland

Cairn Energy has concluded all operations offshore Greenland with the end of the drilling season as agreed with the Greenland Bureau of Minerals and Petroleum (BMP), and the drillship Stena Forth and semisubmersible drilling rig Stena Don have been released off contract.

Cairn said it has suspended its Alpha-1S1 exploration well in the Sigguk Block approximately 175 km offshore Disko Island, west Greenland, to allow possible re-entry to sidetrack or deepen the well at a later date, and that the T8-1 and T4-1 exploration wells have been plugged and abandoned. It said the Alpha-1S1 well encountered oil shows in the volcanic section. In accordance with the BMP regulations, however, drilling operations ceased as of 30 September with the well still in volcanics and the prognosed Mesozoic section had not been reached.

The T4-1 well, which was targeting a Tertiary objective at a different stratigraphic level to T8-1, failed to encounter any significant hydrocarbons and found only thin reservoir sands, although geochemical analyses continue on selective samples. The T8-1 well, which encountered gas in thin sands has also been plugged and abandoned. Neither well resulted in commercial discoveries and their costs, some US$185 million, will be written off.

Cairn said since the primary objectives of the Alpha prospect were not reached, the well was suspended and any future re-entry work will depend on further evaluation.

Geophysical operations in Greenland are still active with a 2,500-km 2D seismic survey currently ongoing on the Eqqua Block, with some data to also be acquired in the Sigguk Block (less than 215 km) for well-tie purposes. A 7,400-km 2D survey was completed during the summer across the offshore south Greenland blocks.

Cairn said it has now drilled one third of all exploration wells ever drilled offshore Greenland and the first wells in the Greenland Arctic for almost 35 years, and that its campaign has demonstrated that drilling operations can be successfully and safely carried out in this area.

Mike Watts, Cairn's deputy CEO, said, "Exploration in Greenland is at a very early stage and consequently to have encountered both gas and oil in two of the first frontier exploration wells in the previously undrilled Baffin Bay geological basin is extremely encouraging. Cairn continues to evaluate all the data acquired this summer. Plans for the forward exploration program in 2011 are already underway and will be announced in the first quarter of 2011."

Cairn is the operator of the Sigguk Block and the three wells with 77.5% interest in partnership with Greenland's national oil company, Nunaoil, and Petronas Carigali, which holds 10% interest. Nunaoil is carried through the exploration phase but has a 12.5% stake in any development.

Rodinia, Ensign Australia partner for six-well drilling program

Rodinia Oil Corp. has announced that its Australian subsidiary, Officer Basin Energy Pty. Ltd., has executed an agreement with Ensign Australia Pty. Limited (“Ensign”) to carry out its initial six well drilling program. Rodinia’s drilling program will initially test six separate large structural targets using Ensign’s Rig 16 in the Officer Basin in South Australia, with drilling to begin in February 2011.

Rodinia is an international oil and gas company engaged in the exploration, acquisition and development of world-class onshore petroleum and natural gas assets in Australia’s Officer Basin. According to independent reserve evaluation firm, Ryder Scott, the estimated fair market value of Rodinia’s land holdings total $77 million and contain a potential 26.2 billion barrels of oil.

Petrobras drills ninth well in Tupi Field

Petroleo Brasileiro has concluded the drilling of the ninth well located in the Tupi area of Brazil's ultra deep Santos Basin Block BM-S-11, confirming the estimated volumes of recoverable light oil and natural gas to be in the range of between 5 and 8 billion boe in the pre-salt reservoirs of the Tupi area.

The well (known as Tupi SW) proved that the oil accumulation, not only is extended until the south extreme of Tupi's Evaluation Plan Area, but also proved that the thickness of the oil reservoir reaches around 128 m, thus reducing the uncertainty of the hydrocarbons volume estimate for Tupi's area.

The result of the drilling of this well is of significance because once it has defined, among other variables, the level of oil/water contact in the prospect, indicates the higher thickness of the oil rock.

Besides the high recoverable estimated volume, the oil in Tupi has a density of 28° API, which corresponds to an excellent commercial value. The declaration of commerciality is expected before December 31. Before then, two delimitation wells will be drilled.

The new well, is located in Tupi's Evaluation Plan Area, in a water depth of 2,152 m, around 290 km off the coast of Rio de Janeiro state and 11 km southwest of the Tupi Sul well, where the extended well test is being performed in the pre-salt reservoirs of Santos Basin. After confirming the expected productivity, the contractor group for BM-S-11 will study the allocation in the south of Tupi, of one of the standardized floating platforms that are being projected to operate in the pre-salt of Santos Basin. All activities and investments are being carried out in accordance with the evaluation plan already approved by Agencia Nacional do Petroleo (ANP).

Petrobras is the operator of Block BM-S-11 with 65% interest in partnership with BG Group, holding 25%, and Galp Energia, with the remaining 10% interest.

Tanzania's first deepwater well hits gas pay

Ophir announced that the Pweza-1 exploration well in the Mafia Basin offshore Tanzania has encountered a thick section of gas-bearing sands. The Pweza-1 well was drilled by Odfjell's semisub Deepsea Stavanger. Results from the Pweza-1 well, which has the potential to de-risk other prospects and leads in the basin, are currently being evaluated.

The Pweza-1 well is located in Block 4 which is operated by one of Ophir's wholly owned subsidiaries on behalf of a joint venture which consists of itself (40%) and BG International ("BG") (60%). The well is located approximately 85km from the coastline in a water depth of 1,400 meters. The Ophir/BG group joint venture has interests in Blocks 1, 3 and 4 offshore Tanzania which cover more than 27,000sq km of the Mafia Offshore Basin and northern portion of the Ruvuma Basin, in water depths ranging from approximately 100m to greater than 3,000m.

Pweza-1 is the first of a three-well initial work program planned for Blocks 1, 3 and 4. The program also includes the acquisition of 4 000 square kilometers of 3D seismic data. BG Group has the option to assume operatorship of all three Blocks upon completion of the initial work program.

The Ophir/BG joint venture now proposes to drill a further two wells as part of this first ever deepwater drilling campaign in Tanzania.

Ophir's Managing Director, Dr Alan Stein, commented, "The success of the Pweza-1 well is an excellent result for both the joint venture partners and for the Government of Tanzania on whose behalf we are exploring the area. This is the first deepwater well drilled in Tanzania. It has the potential to de-risk additional prospects and leads within the basin, providing a solid platform for further investment. A further two wells will now be drilled before the end of the year and we look forward to acquiring more 3D seismic data early next year. The joint venture has already negotiated a comprehensive series of agreements with the Government which provide a mechanism for the commercialization of offshore gas reserves."

Chevron sanctions first lower tertiary deepwater project in Gulf of Mexico

Chevron has sanctioned development of the Jack/St. Malo project, its first operated project located in the Lower Tertiary trend in the deepwater U.S. Gulf of Mexico.

"Jack/St. Malo is the latest example of Chevron advancing its industry-leading queue of major capital projects," said George Kirkland, vice chairman, Chevron Corporation. "The Lower Tertiary is recognized as a huge resource with the potential for long life projects of up to 30 to 40 years and the opportunity to enhance recoveries through technology."

The Jack and St. Malo fields are located within 25 miles (40 km) of each other approximately 280 miles (450 km) south of New Orleans, Louisiana, in water depths of 7,000 feet (2,100 m). The initial development of the project will require an investment of approximately $7.5 billion. It will be comprised of three subsea centers tied back to a hub production facility with a capacity of 170,000 barrels of oil and 42.5 million cubic feet of natural gas per day. Startup is anticipated in 2014.

The Jack and St. Malo fields are estimated to contain combined total recoverable resources in excess of 500 million oil-equivalent barrels. Seven exploration and appraisal wells have been successfully and safely drilled at these fields since 2003. Chevron, through its subsidiary Chevron U.S.A. Inc., has working interests of 50 percent in the Jack field, 51 percent in the St. Malo field, and 50.67 percent in the host facility.

Chevron is one of the top leaseholders in the Gulf of Mexico, averaging net daily production of 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids during 2009.

Success Story: Logging service - Canada | BakerHughes.com

Success Story: Logging service - Canada | BakerHughes.com

Total makes gas discovery in North Sea David prospect

Total E&P Norge AS made a gas/condensate discovery in well 25/5-7 on the David prospect, located about 12 miles (20 kilometers) northeast of the Heimdal field in the Norwegian sector of the North Sea. A gas column of about 230 feet (70 meters) was encountered in the Brent group (primary target) with better reservoir rocks and reservoir quality than expected.

The Statfjord formation, the secondary target, has good reservoir properties, but with aquifers. Preliminary estimates of the size of the discovery range between 2.4 and 3.2 million cubic meters of recoverable oil equivalents. Drilled by the Ocean Vanguard semisub, the well was not formation tested, but data was gathered. The partners in the license are considering connecting the discovery to the Heimdal field.

Total, serving as operator of the license, holds a 40% interest; Petoro holds 30%; Centrica Resources holds 20%; and Det norske holds the remaining 10%.

Total E&P Norge AS, operator of production license 102 C, is in the process of completing the drilling of wildcat well 25/5-7. The well is located about 20 kilometers northeast of the Heimdal field in the North Sea.

The primary exploration target for the well was to prove petroleum in the Middle Jurassic reservoir rocks (the Brent group). The secondary target was to prove petroleum in the lower Jurassic reservoir rocks (the Statfjord formation).

A gas column of 70 meters was encountered in the Brent group with better reservoir rocks and reservoir quality than expected. The Statfjord formation also has good reservoir properties, but with aquifers.

Preliminary estimates of the size of the discovery range between 2.4 and 3.2 million cubic meters of recoverable oil equivalents.

The well was not formation tested, but comprehensive data collection and sampling have been carried out. A gas-condensate reservoir of about 3000 Sm3/Sm3 is expected. The licensees in the production license will consider producing the discovery via the Heimdal field.

The well is the first wildcat well in production license 102 C. The well was drilled to a vertical depth of 3,045 meters below sea level, and was terminated in the Hegre group in the upper Triassic. Water depth at the site is 119 meters. The well will now be plugged and abandoned.

Well 25/5-7 was drilled by Ocean Vanguard. The drilling facility will now travel to production license 303, north of the Sleipner area in the North Sea, to drill delineation well 15/6-11 S, where Statoil ASA is the operator.

Reliance to complete Bay of Bengal exploration drilling

Reliance Industries has been instructed by India's Directorate General of Hydrocarbons (DGH) to complete its commitment exploration drilling offshore India's east coast in the Bay of Bengal Block KG-DWN-2001/1 (D-9 Block).

Sources at Reliance said today that the company anticipates bringing the exploration phase of its operations in the 2.8 million acre D-9 Block to a close before the end of the year. The company has already drilled the first two of the required three wells and is expected to commence the third well right away. The first well, KG-D9-A1 was drilled to a total depth of 4,800 meters (15,749 ft). The second well has been partially completed.

In addition to the three-well exploratory drilling requirement in Reliance's minimum work program for the D-9 Block, it was required to undertake a minimum 1,650 sq km 3D seismic survey, which has been concluded with more than twice that area, some 4,000 sq km, shot and processed.

Reliance is the operator of Block KG-DWN-2001/1 with 90% interest in partnership with Hardy Exploration and Production India, the local subsidiary of Hardy Oil & Gas, holding the remaining 10%.

ION expands ArcticSPAN seismic program to offshore Greenland

ION Geophysical has acquired 6,500 km of regional seismic data for sponsoring E&P clients in the Danmarkshavn Basin offshore northeastern Greenland, adding to the 5,300 km of data the company acquired there last season.

ION said that the Danmarkshavn Basin is one of the least explored, most prospective basins in the Arctic region, an area the United States Geological Survey (USGS) estimates could contain nearly 25% of the world's undiscovered oil and gas resources.

ION once again deployed its purpose-designed marine streamer technology to acquire data in the presence of ice. Together, ION's Intelligent Acquisition toolkit and Arctic program management expertise enabled the company to acquire data further north and in the presence of heavier ice than had been previously possible, at the same time mitigating HSE risk and reducing cycle time. As a result, the company is now confident that it has expanded the Arctic operational season to six months, dramatically longer than the industry's traditional acquisition season of one to two months.

Joe Gagliardi, ION's Arctic Solutions and Technology director, said, "This extension to our Greenland regional program was designed to provide a better understanding of high potential petroleum systems including the North Danmarkshavn Salt Basin, the Northeast Greenland Volcanic Province, and the Thetis Basin. The success of the 2010 expansion serves as further confirmation of the viability and value of our proprietary in-ice Arctic solution."

ION's ArcticSPAN program now includes more than 40,000 km of deeply imaged seismic data in the Arctic region covering the Beaufort-MacKenzie, Banks Island, Chukchi, East Greenland Rift, and Danmarkshavn Basins. Together, this data provide E&P companies with an understanding of the relationships among micro basins in the area, which they can use to more effectively assess the Arctic's hydrocarbon potential, identify new opportunities, and mitigate exploration risk.

Anadarko makes deepwater gas discovery off Mozambique

Anadarko announced that the Barquentine exploration well in the Offshore Area 1 of Mozambique's Rovuma Basin encountered a total of more than 416 net feet of natural gas pay in multiple high-quality sands.
The discovery well encountered more than 308 net feet of pay in two Oligocene sands that are separate and distinct geologic features, but age-equivalent to those encountered in Anadarko's previously announced Windjammer discovery. The well also found an additional 108 net feet of gas pay in the Paleocene sands, and the seismic data indicates this deeper pay section is contiguous and appears to be connected to the 75 net feet of pay encountered at the Windjammer discovery, located 2 miles to the southwest.

The Barquentine exploration well was drilled to a total depth of approximately 16,880 feet, in water depths of approximately 5,200 feet. Once operations are complete at Barquentine, the partnership plans to mobilize the Belford Dolphin drillship approximately 16 miles to the south to drill the Lagosta exploration well, also located in the Offshore Area 1 of the Rovuma Basin.

Anadarko currently holds more than 2.6 million acres in the basin where it has identified more than 50 prospects and leads.

Anadarko is the operator with a 36.5-percent working interest in the Offshore Area 1. Co-owners in the area are Mitsui E&P Mozambique Area 1, Limited (20 percent), BPRL Ventures Mozambique B.V. (10 percent), Videocon Mozambique Rovuma 1 Limited (10 percent) and Cove Energy Mozambique Rovuma Offshore, Ltd. (8.5 percent). Empresa Nacional de Hidrocarbonetos, ep's 15-percent interest is carried through the exploration phase.

FX Energy contracts Geofizyka Torun to shoot 2D seismic onshore Poland

FX Energy will begin a new 2D seismic acquisition program during the fourth quarter that is intended to identify drillsites in the company's 640,000-acre Warsaw South Concession (Lublin area) onshore Poland.

FX said today that it has contracted Geofizyka Torun to carry out the 273-km seismic survey, which will be processed and interpreted with plans to begin the tender for the first well in the Warsaw South Concession during January 2011. The first well is expected to begin drilling operations in March or April 2011.

FX Energy owns 100% interest and is the operator of the Warsaw South Concession, which is a virtually unexplored area at the terminus of the Permian Basin southeast of Warsaw. The primary exploration targets in the concession are Carboniferous, Zechstein Ca-1, and Rotliegend.

"We think there could be great potential in the Warsaw South Concession," said David Pierce, CEO at FX, "and we have wanted to explore the block for some time. Now, with our growing cashflow, we have the means to carry out a sustained exploration program in Warsaw South with the hope of opening up a new core area. Our primary focus remains our producing Fences Concession, but we are pleased now to be able to devote meaningful resources to exploration on our other acreage in Poland."

FX Energy also reported today that the Lisewo well in the company's Fences Block is currently drilling at a depth of approximately 1,500 meters. FX holds 49% interest in the Lisewo well, which is operated by the Polish Oil and Gas Company with 51%.

Kårstø gas facility celebrates 25 years in operation

It will be 25 years on 15 October since the first deliveries of dry gas from this facility north of Stavanger were made via the Statpipe and Norpipe lines to Emden in Germany.

Measured from 1 October 1985 to 1 October 2010, the plant has delivered natural and liquefied petroleum gases corresponding to 5 001 terawatt-hours by pipeline and ship respectively.

According to an overview from grid operator Statnett, Norway generated 2 984 TWh of electricity during the same period.

Now celebrating its 25th anniversary, Kårstø is one of Norway’s most important industrial facilities. Its capacity has increased more than fivefold since 1985, and it currently receives gas from 30 fields on the Norwegian continental shelf.

“The importance of Kårstø and the Draupner pipeline hub in the North Sea has not come by itself,” says Kjetil Ohm, head of processing and transport in Statoil’s Natural Gas business area.

“Many years of safe and efficient operation, with high regularity, has been the most important contribution. Each employee and our suppliers have also played a big part in helping to make Kårstø an attractive hub for new gas fields. The fact that we have attracted several thousand visitors from 98 countries in recent years also shows the interest for a plant of this kind in a global context.”

“Kårstø is a key link in the unique value chain which has allowed Norway to become the world’s second largest gas exporter,” says Brian Bjordal, chief executive of operator Gassco. “The history of this plant is nothing less than fantastic, and many people deserve great thanks for making such an industrial achievement possible. Mention must be made of the many thousands who have taken part in building up Kårstø, and of the pioneers who had the vision and drive to push through the decision to create Statpipe and this plant.”

The anniversary will be celebrated at a ceremony for owners, politicians and government authorities at Kårstø from 14.00 on 7 October. Celebrations for the workforce will be held in November and December.

Denbury to sell Haynesville, East Texas gas assets for $217 million

Denbury has entered into an agreement to sell its Haynesville and East Texas natural gas assets for approximately $217.5 million to a private oil and gas company. The sale is expected to close in 30 to 45 days and is subject to satisfactory completion of customary due diligence and closing conditions.

The agreement contemplates an effective date of September 1, 2010, and consequently operating net revenue after September 1, net of capital expenditures, along with other purchase price adjustments, will be accounted for as adjustments to the ultimate sales price.

Production attributable to the properties to be sold averaged approximately 34 MMcfe/d during the second quarter of 2010. The Company expects to utilize a Section 1031 like-kind-exchange with a portion of the proceeds expected from the sale of the Haynesville and East Texas assets and the previously announced Riley Ridge acquisition in order to reduce the estimated taxable gain on the sale.

The Company plans to use the balance of proceeds from the sale to repay most of its currently outstanding bank debt. RBC Richardson Barr acted as advisor to Denbury on the asset sale.

Total, DONG awarded Shetland contract by EMGS

Electromagnetic Geoservices ASA (EMGS) have signed a contract with Total E&P UK Ltd and DONG Energy to acquire 3D electromagnetic (EM) data in the West of Shetland area on the UK Continental Shelf. The value of the contract is estimated at worth approximately $1.5 million.

The 3D EM data acquired by EMGS will be used to de-risk a hydrocarbon prospect. The 3D EM survey has already started using EMGS's mobile acquisition set deployed from the vessel Siem Mollie, thereby extending the charter on this vessel from 1 to 21 October.

Roar Bekker, EMGS chief executive officer, commented: "We are delighted to continue our relationship with Total. The new direct contract award follows a successful 3D EM survey in 2009. The previous survey evaluated its mature North Sea Frigg field to facilitate decommissioning decisions. The two contracts demonstrate the value, which companies such as Total recognize, that EMGS can deliver across the exploration and production life cycle."

US shale gas M&A spending totals $21 billion in first half 2010

Wood Mackenzie’s latest corporate analysis highlights that upstream M&A expenditure in US shale gas totalled US$21 billion during the first half of 2010: equivalent to one third of global upstream M&A spend during the period. The independent energy research firm says key indicators suggest that this level of activity is set to continue over the next couple of years, with the large caps and majors continuing to dominate the market.

Luke Parker, Manager of Wood Mackenzie’s M&A research service underlines the magnitude of the market, “Through the first half of this year alone, in excess of 35 trillion cubic feet (tcf) of shale gas resource changed hands at an average cost of US$0.60 per million cubic feet of gas equivalent (mcfe). This expenditure is equal to the total US shale gas M&A expenditure for the 2008 and 2009 combined – which was US$19.7 billion and US$2 billion respectively.”

“M&A activity in US shale gas has evolved with its emergence, play-by-play, as a world scale source of secure, long-term gas supply. The key factor driving this has been the continued evolution and application of new technologies to unlock enormous volumes that were previously considered uncommercial.” The result is lowered development breakeven costs to a level at which the cost of shale gas is highly competitive with other domestic sources of supply - conventional and unconventional - and LNG imports. Operators have made, and continue to make, notable advances and unit costs have fallen in spite of increasingly complex and specialised well design.

Expanding on how continued level of activity is set to unfold Parker explains, “There’s scope for intra-play and sector wide consolidation, facilitated by mounting pressures on existing players to evaluate and restructure their portfolios as strategic priorities evolve. Key among the various pressures that will influence the market, at least in the near-term, is the continued disconnect between oil and gas prices and a depressed Henry Hub futures market.”

Therefore Wood Mackenzie suggests that gas weighted independents with a weak balance sheet and/or hedging position are beginning to look increasingly vulnerable to larger players. In fact, the report suggests that shale gas offers a good fit for the large caps and majors, playing to their technical capability, financial strength and long-term view, all of which are pre-requisites for those looking to build a material position. Hence this peer group will continue to dominate the large scale deal activity.

Robert Clarke, Unconventional Gas Research Manager for Wood Mackenzie adds, “The magnitude of the US Shale gas resource is extraordinary. We estimate the total resource potential of the 22 shale plays we currently analyse is approximately 650 trillion cubic feet of gas equivalent (tcfe): equivalent to a resource life of 32 years based on total US gas production in 2009. Shale gas production is set to increase from 17% in 2010 to 35% in 2020 of total US gas supply.”

Aker Solutions goes subsea for Shell in Gulf of Mexico

Aker Solutions has signed three subsea contracts with Shell Offshore Inc for deliveries to the operator's Popeye and Europa fields in the Gulf of Mexico. Contract values are undisclosed.

Under the contracts, Aker Solutions will in total deliver approximately 40 km (25 miles) of electro-hydraulic steel tube umbilicals to Shell's Popeye field and Europa field extension. Aker Solutions will also install the umbilical for the Popeye field, using the company's deepwater installation vessel Boa Sub C.

"We have a strategic objective of combining our product and service offerings where they can create attractive business propositions for our customers. The contracts with Shell, where we will first manufacture the subsea umbilical and then install it, is one way of doing this," says Erik Wiik, President - Subsea North America, Aker Solutions.

Engineering, project management, and manufacturing will take place at Aker Solutions' state-of-the-art umbilical facility in Mobile, Alabama. .

"This is an important contract for our umbilical facility in Mobile, Alabama. Although we have vast experience with Shell through our umbilical operations in Norway, this is our first Shell umbilical project to be executed by our team in Mobile, Alabama. Our key objective is excellent project execution, which will position us for further jobs with Shell," adds Wiik.

The Popeye field is located in Green Canyon block 116 in approximately 671.6 metres (2,200 ft) water depth and will tie-back to the Cougar fixed platform located in South Timbalier block 300 in 110.3 metres (362 ft) water depth.

The Europa A7 well is located in Mississippi Canyon block 935 in approximately 1143 metres (3750 ft) water depth and will tie-back to existing Europa subsea structure. The Europa development ties back to the Mars TLP located in Mississippi Canyon block 807 in 896 metres (2,940 ft) water depth.

Aker Solutions' contract parties are Aker Subsea Inc and Aker Marine Contractors Inc. The contracts are signed and booked as order intake in Q3 2010.

GE introduces first mobile evaporator for treating shale gas frac water on-site

Further advancing a solution for unconventional gas production, GE has introduced a mobile evaporator, specifically designed to help natural gas producers recycle untreated waters that result from the hydraulic fracturing process at the well site. GE’s new, completely mobilized evaporator is energy efficient, fully transportable, cost effective and will enable onsite frac water recycling, reducing the volume of wastewater and fresh water that needs to be hauled to and from the site.

GE’s mobile evaporator will be used for all unconventional gas and frac water applications in regions of the world where shale gas can be found, including North America, Europe, China and Indonesia. Initial applications will be in various North American markets such as the Marcellus Shale reservoirs located in the Appalachian Basin.

Regions like the Marcellus Shale are unique in that they produce very high total dissolved solids (TDS) frac water, have limited deep well capacity and increasingly stringent discharge regulations. The mobile evaporator will enable natural gas producers to significantly decrease their transportation and disposal costs. Additionally, the communities will benefit from less truck traffic and decreased wear and tear on local roads. The first units will be available in early 2011.

“GE’s objective is to create a solution that not only lessens the environmental impact of gas drilling, but also one that reduces the current treatment cost to service providers and producers. As the mobile evaporator illustrates, our research and development teams are continually working toward offering new solutions to meet our customers’ challenges throughout the industry,” said Jeff Connelly, vice president, engineered systems—water and process technologies for GE Power & Water.

The mobile evaporator is a 50-gallon per minute, horizontal, shell and tube, forced circulation, mechanical vapor recompression system. Unlike other treatment methods, thermal evaporation removes nearly all of the impurities in the water, allowing producers to easily meet the newly passed Pennsylvania discharge regulations of less than 500 TDS. The mobile evaporator is mounted on a single trailer that will allow it to reach the most remote drilling sites. Additionally, its unique design has been optimized for maximum energy efficiency.

GE has offered thermal evaporation technology for more than 40 years, but this is the first time that the technology used for the treatment of shale gas frac water has been completely mobilized.

Major oil reservoir discovered in Xinjiang

Commercial oil flows have been found by PetroChina in wells in the Mobei oilfield in the oil-rich Xinjiang Autonomous region of northwest China. A high-quality uncompartmentalized light oil reservoir has been proven. Parent company China National Petroleum Corp. announced that it expects to add new crude oil reserves of tens of millions metric tons.

Wells 121 and 122 in Block 116 of the Mobei oilfield, have yielded oil flows, and are located in Xinjiang Junggar Basin.

Seneca fined for operating violations in Marcellus Shale

The Department of Environmental Protection has fined a Marcellus Shale driller $40,000 and ordered it to correct multiple violations after discovering that the company illegally built an impoundment on wetlands in Tioga State Forest.

DEP inspected the Bloss Township, Tioga County, site in March and found that Seneca Resources Corp. of Brookville had filled nearly one acre of “exceptional value” wetland without authorization, improperly built an impoundment, and caused sediment runoff by failing to institute erosion control best management practices.

The unauthorized fill in a wetland and sediment runoff were violations of the Pennsylvania Clean Streams Law and the Dam Safety and Encroachments Act.

“Wetlands are highly protected in Pennsylvania for a number of reasons, but largely because many plant and animal species depend on them for survival,” said DEP North-central Regional Director Nels Taber.

Exceptional value wetlands receive special protection under DEP’s Chapter 105 Dam Safety and Waterway Management regulations based on certain characteristics. The wetland that was improperly filled by Seneca received the classification because it was located along the Johnson Creek floodplain, a wild trout stream in the Tioga River watershed.

DEP issued an Erosion and Sediment Control General Permit No. 1 to Seneca in November 2009 so the company could build a fresh water impoundment to store water for use in hydraulically fracturing Marcellus Shale natural gas wells.

To correct the violations, DEP’s Oil and Gas Program required Seneca to submit a wetland restoration and mitigation plan.

DEP approved the plan and the wetland restoration is underway. Seneca has removed fill from the impacted wetland, but not finished final grading or constructed the new, 0.86-acre exceptional value wetland.

Stellar, Elk Hills Heavy Oil discover new heavy oil field in Montana

Stellar Resources Ltd. announced today that Elk Hills Heavy Oil LLC, (EHHO) has discovered a new oil field, which is to be named the Morris Field. The Morris Field is approximately 1,000 acres in size and is located within the 22,000 acre Elk Hills Project in Carbon County, Montana.

The first well in the Morris Field, successfully cored and logged the Tensleep formation. Prisem Geoscience Consulting of Spokane, WA estimates that the Morris Field contains approximately nine million (9,000,000) barrels of oil-in-place. A continuous ninety-three feet of four inch core has been recovered from the Tensleep formation for the purposes of technical evaluation of reservoir qualities. Seven inch production casing has been run.

EHHO is now drilling its second exploration well on the Elk Hills property.

CNOOC buying $2.16 billion of Chesapeake's Eagle Ford assets

CNOOC International Limited, a wholly-owned subsidiary of CNOOC Limited, will purchase a 33.3% undivided interest in Chesapeake's 600,000 net oil and natural gas leasehold acres in the Eagle Ford Shale project in South Texas. The consideration for the sale will be $1.08 billion in cash at closing, subject to adjustment. In addition, CNOOC Limited has agreed to fund 75% of Chesapeake's share of drilling and completion costs until an additional $1.08 billion has been paid, which Chesapeake expects to occur by year-end 2012. Closing of the transaction is anticipated in the 2010 fourth quarter.

As operator of the project, Chesapeake will conduct all leasing, drilling, completion, operations and marketing activities for the project. Over the next several decades, the companies plan to develop net unrisked unproved resource potential up to 4 billion barrels of oil equivalent (after deducting an assumed average royalty burden of 25%). Chesapeake is currently utilizing 10 operated rigs to develop its Eagle Ford leasehold and with the additional capital from CNOOC Limited, anticipates increasing its drilling activity to approximately 12 operated rigs by year-end 2010, approximately 31 rigs by year-end 2011 and approximately 40 rigs by year-end 2012. Approximately 900 wells are expected to be drilled by year-end 2012.

Currently Chesapeake has 10 horizontal Eagle Ford wells in production with initial production rates of up to 1,160 barrels of oil and 0.4 mmcf of natural gas per day in the oil window and 4.0 mmcf of natural gas and 1,200 barrels of oil per day in the wet gas window. Chesapeake anticipates the project will reach its peak production of 400,000-500,000 barrels of oil equivalent per day in the next decade.

The assets are located principally in the counties of Webb, Dimmitt, LaSalle, Zavala, Frio and McMullen, and are located primarily in the oil window (~85%) and the wet gas window (~15%) of the Eagle Ford Shale and in the dry gas window of the Pearsall Shale. CNOOC Limited will have the option to acquire its 33.3% share of any additional acreage acquired by Chesapeake in the area and also the option to participate with Chesapeake for a 33.3% interest in midstream infrastructure related to production established from the assets.

BNK picks Nafta to drill 2 wells in Poland's Slawno & Slupsk Blocks

BNK Petroleum's Polish subsidiary Saponis Investments has completed the major tenders for the services to drill the Wytowno S-1 and Lebork S-1 wells on the Slawno and Slupsk Blocks in Poland's Baltic Basin.

The company said that the drilling contract has been awarded to Poszukiwania Nafty I Gazu Nafta Pila, wa unit of Polskie Gornictwo Naftowe i Gazownictwo (PGNiG), which recently completed drilling the Lebien LE1 well and is currently drilling the Legowo LE1 well, both for Lane Energy/ConocoPhillips and drilled with the company's Mass 5000 rig. It said that these two wells are shale gas test wells located on concessions directly offsetting the company's Saponis concessions.

Surface agreements have been secured for both the Wytowno S-1 and Lebork S-1 wells, and surface site construction is underway. The rig release and mobilization from the Legowo LE1 well and site construction will determine the Saponis drilling schedule. BNK owns 26.6% of Saponis with the remaining equity held by Rohol-Aufsuchungs Aktiengesellschaft (RAG), Sorgenia E&P, and LNG Energy through a subsidiary. The company is obliged to pay approximately 6.6% of the drilling costs of these first two wells with the other 20% of the company's interest being paid by RAG and Sorgenia under the terms of the BNK's farmout to

RAG and Sorgenia. The company holds 195,000 net acres in Poland through Saponis and a further 880,000 adjacent net acres through another European subsidiary.

Petrobras makes new gas discovery in Peru

Petrobras announced a new natural gas discovery in Lot 58, of which its Petrobras Energia Peru S.A. (PEP) subsidiary is the operator with a 100% interest, located in the Department of Cuzco, near Camisea.

The discovery was the result of the drilling of exploratory well Picha 2X, with a final depth of about 4,400 meters. The well is currently under assessment and is the second discovery made in this lot. The first, called Urubamba 1X, was announced in late 2009.

Preliminary estimates indicate a potential and recoverable volume of gas of 1.7 TCF (48 billion cubic meters) in the two exploratory wells.

TGS announces multi-client 3D survey in deep waters off Gambia

TGS has announced its first new multi-client 3D survey, which covers 2,500 km2 in the deep water area offshore Gambia.

TGS has chartered the M/V Geo-Caribbean as previously mentioned in a press release on 12 July 2010, to acquire the data. This project is the first of a series of surveys in the African Transform Margin. The Geo-Caribbean is a modern 3D vessel that will tow twelve (12) long offset streamers on this project. Specialized data processing will be done at TGS' imaging center in Houston, TX.

The Gambia multi-client 3D survey is supported by industry funding.

Aurelian strikes 100-meter gas column in Poland’s Trzek-2 well

Aurelian Oil & Gas has obtained good gas readings and core indicating an estimated 100-meter gas column in its first multi-fracced horizontal well drilled in Poland's Rotliegendes Sandstone.

Aurelian said today that the Trzek-2 well, being drilled with the Nafta Pila IDM 2000 drilling rig, part of the company's Siekierki Tight Gas Project on the Poznan Block, penetrated the top reservoir with its vertical section and, following coring and logging, it will be sidetracked and drilled horizontally toward the 91-meter gas column discovered by the Trzek-1 well. Completion of frac and flowtesting is expected during December in line with planned well schedule and budget, with Halliburton carrying out the frac job.

Trzek-2 is targeting approximately 16 to 28 bcf of recoverable gas reserves on the 346 bcf, net to Aurelian, Siekierki Field which is expected to be onstream in the second half of 2011. Following the completion on the Trzek-2 well, the rig will be mobilized to the Trzek-3 drillsite.

The Siekierki Field is located in the Poznan license area which is 100% held and operated by Energia Zachod, a company owned 90% by Aurelian and 10% by Avobone Poland.

New Strong-Handed Dinosaur May Shatter Assumptions

New Strong-Handed Dinosaur May Shatter Assumptions

Operator saves more than $1.8 million using casing bit system

Operator saves more than $1.8 million using casing bit system

Jacobs Receives Contract to Expand Chemical Plant

Jacobs Engineering Group Inc. announced that it received a contract from Huntsman Corporation to provide engineering, procurement, construction management and turnaround management services for a capacity expansion of Huntsman's polyether amines manufacturing facility on Jurong Island, Singapore. The work will be executed by Jacobs' office in Singapore.

Officials did not disclose the contract value.

Jacobs' scope of work for the project includes the design and installation of a third reactor at the manufacturing facility to increase the production capacity of the product. This expansion is expected to help meet the increasing demand for polyether amines, particularly in the Asia-Pacific region.

In making the announcement, Jacobs Group Vice President Christopher E. Nagel stated, "We appreciate Huntsman's confidence in us. This project further advances the long and successful relationship between our two companies. We are committed to help Huntsman efficiently execute the expansion of its world-class manufacturing facility at Jurong Island."

Total E&P Vietnam makes second oil discovery at Lac Da Vang prospect

Total announced that its subsidiary, Total E&P Vietnam, and its partners on Block 15-1/05, have discovered oil in the Lac Da Vang prospect, located in the southern part of the block in the Vietnamese offshore.

The Lac Da Vang exploration well is located approximately 125 kilometers to the East of the city of Vung Tau, about 65 kilometers off the coast, and was drilled in a water depth of 48 meters. The well produced up to 3,500 barrels per day of 43 API° oil during tests.

On this Block, which was attributed in 2007, this is the second exploration well drilled and the second discovery made in less than a year. Lac Da Vang is located 15 kilometers East-North East of Lac Da Nau, the first discovery announced in November 2009.

Phu Quy Petroleum Company, a subsidiary of Petrovietnam Exploration and Production Corporation, is the operator with a 40% stake. The other partners on Block 15-1/05 are Total E&P Vietnam (35%) and SK Energy (25%).

MOG, Leni prepare pre-drilling program off Malta

Mediterranean Oil & Gas (MOG) and partner Leni Gas & Oil are gearing up to commence an exploratory drilling program offshore Malta in the southern part of the Maltese sector of the Mediterranean Sea.

Leni said that it is focused on assessing the viability of non-seismic surveys and acquiring additional seismic data in the area south of Malta ahead of starting to drill an exploratory well next year. It said that it and MOG have until July 2011 to drill an exploration well in compliance with their production sharing agreement with Malta's Resource Ministry.

"Four prospects and five leads on the 5,700 sq km PSC Area 4 have been delineated, with the total most likely hydrocarbon potential estimated at a gross 5 billion bbl of oil in place with resultant total most likely case prospective recoverable oil resources of 1.475 million bbl gross," Leni said. Its chairman, David Lenigas, adding, "'Malta is the company's only non-producing asset though it has company-maker potential with a billion-bbl resource base. During the reporting period, the company and the joint venture operator continued to progress the pre-drilling work program to improve the understanding of all drilling prospects. This work program continues to maximize the chance of success of the first Malta drilling target."

Mediterranean Oil & Gas is the operator of Malta's Area 4 Blocks 4, 5, 6, and 7 with 90 interest, with Leni holding the remaining 10%.

Shell, Nexen estimate GOM Appomattox discovery to hold 250 million boe

Shell Offshore and its partner Nexen have completed the drilling of additional appraisal wells for their Appomattox Field discovery in the deepwater sector of the eastern US Gulf of Mexico.

Nexen said today that based on the two appraisal sidetracks and the discovery well itself, the partners have estimated the recoverable contingent resource exceeds 250 million boe with upside potential. It said that once drilling resumes in the Gulf of Mexico, further appraisal wells are to be drilled to determine ultimate reserves and move towards development plans which potentially include a new hub.

The Appomattox discovery was made in waters 2,200 meters (7,217 ft) in depth in Mississippi Canyon Blocks 391 and 392, with the discovery well in Block 392 drilled with Transocean's Deepwater Nautilus semisubmersible drilling rig to a total depth of 7,643 meters (25,077 ft) to encounter approximately 162 meters (530 ft) of oil pay. The appraisal sidetrack was then drilled to 7,910 meters (25,950 ft) and encountered another 116 meters (380 ft) of oil pay.

Shell is the operator of Mississippi Canyon Blocks 391 and 392 and the Appomattox discovery well with 80% working interest in partnership with Nexen, which holds the remaining 20%. The partners are currently investigating development options for the discovery.

BHP Billiton gets green light for Macedon gas development in W. Australia

BHP Billiton gets green light for Macedon gas development in W. Australia BHP Billiton has announced approval for development of the Macedon gas field in the Exmouth Sub-basin, Western Australia.

The Macedon Gas Development, to be operated by BHP Billiton, will commercialise natural gas from offshore production lease WA-42-L, located 100 kilometres west of Onslow. First production is expected during calendar year 2013. Recoverable reserves for the Macedon field are between 400 and 750 billion cubic feet of gas. Project costs will be approximately US$1.5 billion, of which BHP Billiton’s share will be 71.43 percent (approximately US$1,050 million). The balance will be invested by joint venture partner Apache Northwest with a 28.57 percent interest.

The Macedon project involves four offshore production wells supplying a wet gas pipeline to an onshore gas treatment plant to be constructed at Ashburton North, 17 kilometres south west of Onslow. A sales gas pipeline will be connected to the Dampier to Bunbury Natural Gas Pipeline for sale to the domestic gas market in Western Australia. The gas plant will have a design capacity of 200 million standard cubic feet per day.

J. Michael Yeager, Chief Executive BHP Billiton Petroleum said today that the Macedon project would be an important addition to the Company’s portfolio of Western Australian projects.

The Macedon Gas Development will build on BHP Billiton’s existing producing interests in the north west region of Australia including its operated Stybarrow and Pyrenees projects and non-operated North West Shelf Venture.

Fluor Awarded Hijau Gasoil Phase-1 in Malaysia

Fluor Corporation was awarded the Project Hijau Gasoil Phase-1 by Shell Refining Company FOM Malaysia. The project comprises a new 6,000 tonnes-per-day diesel processing unit located in Port Dickson, Malaysia. Fluor will perform engineering, procurement and construction management (EPCM) services as a follow-on scope of work to its previous front-end engineering and design (FEED) work. Fluor will recognize the undisclosed award value in the third quarter of 2010.

"This important new project award from Shell follows our successfully completed FEED work on Hijau. We appreciate the confidence that Shell has demonstrated in Fluor by awarding us this next phase to bring the project to reality," said Peter Oosterveer, president of Fluor's Energy & Chemicals Group. "Southeast Asia is a strategic geography for both Shell and Fluor, and this EPCM project will further solidify our strength in this area."

The project is expected to peak at approximately 650 craft and professional employees with work performed from Fluor's Manila, the Philippines; Haarlem, the Netherlands offices; and the Kuala Lumpur project site.

CNPC discovers major gas field in Turkmenistan

A major gas field has been discovered by China National Petroleum Corporation (CNPC) in its Block B concession in eastern Turkmenistan. The discovery was made by its Turkmenistan subsidiary CNPC Amu Darya River Natural Gas Corp. on the Oja-21 exploration well. The well was drilled on the right bank of the Amu Darya River. Under test the well flowed at a rate of 50.82 Mcfd of natural gas and 227.7 bpd of condensate; the tests also indicated that the reserves of more than 3.53 Tcf have the potential of becoming a highly productive field.

This is the second significant gas field discovery by CNPC in the Bagtyyarlya area of Turkmenistan's Lebapsk region's Khodzhambask District. CNPC reported a 2.57-Tcf find in June at Agayra. It has been reported that CNPC has invested about US$1.5 billion in Bagtyyarlyk.

Total makes new oil discovery offshore Angola

Total announced that its subsidiary, TEPA (Block 15/06), Limited, and its partners have made a new oil discovery in Block 15/06 with the well Cabaça SE-1, in the Angolan deep waters. The exploration effort of the Block 15/06 partnership has reached a significant milestone with six commercial discoveries out of the seven prospects drilled to date.

The well, located in 470 meters of water depth and 100 kilometers from the Angolan shore line, encountered significant gross thickness oil bearing reservoirs in the Miocene series. Volumes estimates suggest that Cabaça SE could hold substantial volumes of oil in place, with a potential yet to be confirmed.

An appraisal well is planned to be drilled in the third quarter 2010 with the objective of delineating and testing this oil accumulation.

Cabaça SE-1 is the seventh exploration well drilled in Block 15/06 since the block award at the end of 2006. The eighth well of the exploration drilling campaign (Mpungi-1) is currently being drilled, and it will complete the work commitment of the first exploration period one and a half year in advance of the contractual period.

TEPA (Block 15/06), Limited, holds a 15% interest in the Block 15/06, operated by Eni.

ONGC makes gas discovery in Krishna Godavari Basin onshore India

Oil and Natural Gas Corporation (ONGC) has made a gas discovery in the Krishna Godavari Basin onshore eastern India with its Vygreswram Southwest-1 exploration well drilled in PEL Block-1B of KG (Onland), KG-PG Basin.

ONGC said that it has notified India's Directorate General of Hydrocarbons (DGH) of the gas find, which proved a 30-meter gas column on testing and produced gas at a consistent flowrate of approximately 2.6 million cf/d of natural gas and 18.8 million b/d of condensate. It said that the well was drilled to a total depth of 4,600 meters (15,093 ft) to explore the syn-rift Cretaceous sequence.

The Indian national oil company said that this new discovery has further established the prospectivity of Raghavapuram play towards the southwest of VG-1 in the north Pasarlapudi area.

"Our recent exploratory successes are the result of a two pronged strategy of targeting deeper as well as shallower targets in operational areas in different basins. This strategy has given rich dividends in the form of discoveries made," ONGC said, noting that exploration efforts have resulted into significant finds at Vygreswaram, South Mahadevpattanam, and Penugonda in the KG onshore area, adding 18.50 million tons of oil and oil equivalent gas reserves. Similar efforts in Assam and Assam Arakan Basin have resulted into discoveries at Disangmukh and Panidihing in Tura Formation in the past. In the Western onshore basin, Charada, Halisa, and Gamij finds have resulted in accretion of 23 million tons of oil and oil equivalent gas reserves.

In addition, ONGC today reported it has spudded a first shale gas well, RNSG-1, in Ichapur village near Durgapur in West Bengal.