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Showing posts with label Hits. Show all posts
Showing posts with label Hits. Show all posts

Tuesday, September 13, 2011

Det norske Hits Pay in Norwegian Sea

- Det norske Hits Pay in Norwegian Sea

Tuesday, September 13, 2011
Det norske oljeselskap ASA

Det norske oljeselskap ASA, operator of PL 482, is in the process of completing exploration well 6508/1-2 on Skaugumsåsen. The well is located about 10 kilometers south of the Norne field in the Norwegian Sea.

The well encountered an 18 meter gas column and a 23 meter oil column.

Preliminary estimates of the discovery indicate recoverable volumes of 1 million Sm3 oil equivalents. Further studies are necessary in order to determine if the discovery is economically viable.

This is the first exploration well in license 48, which was part of the Awards in Predefined Areas (APA) 2007.

Well 6508/1-2 was drilled by the semisubmersible Aker Barents rig.

Partners in PL 482 include: Det norske (65 percent and operator), Petoro 20 percent and Skagen44 AS 15 percent.

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Friday, September 9, 2011

Total Hits Gas Pay in Caspian

- Total Hits Gas Pay in Caspian

Friday, September 09, 2011
Total S.A.

Total on Friday announced a major gas discovery in the Caspian Sea in the Absheron block offshore Azerbaijan.

The Absheron X-2 well has encountered more than 500 feet of cumulated net gas pays within high quality sands on the northern flank of a major 270 square kilometers structure. Reservoirs are expected to extend over the entire northern part of the structure.

The well's first results confirm a potential of several trillion cubic feet of gas and associated condensates.

"This discovery could be very significant in terms of resources," said Total's Senior Vice President Exploration, Marc Blaizot. "It is the result of Total's bolder exploration strategy aimed at exploring high risk/high reward prospects both in prolific and frontier basins particularly in high pressure, deeply buried reservoirs. Our geoscientists and drillers have all the skills to make other discoveries in similar environments like the United Kingdom, Brunei, Malaysia or Egypt where new permits have been recently awarded to Total."

The well is currently at a depth of approximately 6,550 meters. Drilling will continue to explore further deeper objectives that look attractive. The well will then be tested to better confirm the reservoir potential.

The Absheron discovery is located in 500 meters of water, 100 kilometers south east of Baku, some 25 kilometers north east of the Shah Deniz gas and condensate field.

Total subsidiary, Total EP Absheron is the operator of the Absheron license with a 40% equity. The partners are SOCAR (40%) and GDF SUEZ (20%).

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Monday, August 22, 2011

Anadarko Hits Gas Pay Offshore Mozambique

- Anadarko Hits Gas Pay Offshore Mozambique

Monday, August 22, 2011
Anadarko Petroleum Corp.

Anadarko announced that its Barquentine-2 appraisal well, located in Mozambique's Offshore Area 1 of the Rovuma Basin, encountered more than 230 net feet (70 meters) of natural gas pay in high-quality Oligocene-age reservoirs. Barquentine-2 was the first appraisal well in the Windjammer, Barquentine and Lagosta complex, which is estimated to hold a minimum of 6 trillion cubic feet (Tcf) of recoverable natural gas resources.

"Our first appraisal of the Barquentine discovery matched our expectations, confirming our seismic modeling and providing confidence in our geologic interpretation of this world-class accumulation," Anadarko Sr. Vice President, Worldwide Exploration Bob Daniels said. "We've also taken a major step toward the development of these substantial resources by awarding contracts for pre-FEED (front-end engineering and design) work for a prospective LNG (liquefied natural gas) plant. We have significant ongoing exploration and appraisal programs in the Rovuma Basin and look forward to advancing this important project that can provide long-term benefits for the people of Mozambique."

The Barquentine-2 appraisal well was drilled to a total depth of approximately 13,500 feet (4,100 meters) in approximately 5,400 feet (1,650 meters) of water using drillship Belford Dolphin. The results of the Barquentine-2 appraisal well, which is located approximately 2 miles (3 km) east-southeast of the Barquentine-1 discovery well, also indicated that the Oligocene reservoirs are in static pressure communication between the wells. The drillship is now being mobilized to the south to drill the Camarão exploration well, which also will serve as an appraisal to the Windjammer discovery.

As mentioned, a subsidiary of Anadarko and co-owners in the Offshore Area 1 awarded contracts to KBR and Technip to perform pre-FEED studies for an LNG plant in Mozambique. The pre-FEED studies are designed to help the partnership further assess the viability of developing an LNG facility to produce and process natural gas from the region.

Anadarko is the operator of the 2.6-million-acre Offshore Area 1 with a 36.5-percent working interest. Co-owners in the area include 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, E.P.'s 15-percent interest is carried through the exploration phase.

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Thursday, August 4, 2011

Lundin Hits Gas Pay Offshore Malaysia

- Lundin Hits Gas Pay Offshore Malaysia

Thursday, August 04, 2011
Lundin Petroleum AB

Lundin has made a second gas discovery with the Cempulut-1 well that was drilled in Block SB303, offshore Sabah, East Malaysia.

Cempulut-1 was drilled with the Offshore Courageous rig in a water depth of approximately 75 meters. The well was drilled to a total depth of 1,095 meters.

The Cempulut-1 well intersected a large Late Miocene carbonate reef with excellent reservoir properties.

The gross total vertical pay thickness encountered is approximately 50 meters. The deeper targeted oil leg however proved to be water bearing.

An extensive data acquisition program was completed including pressure measurements, sampling and a mini flow test.

The data recovered from the well will be analyzed further in order to determine a range of resource estimates.

Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "This is the second gas discovery made by Lundin Petroleum in SB303 and the third in the contract area which also contains the Titik Terang discovery. All three discoveries are in close proximity to one another and with additional undrilled leads and prospects also in the block a clear opportunity to evaluate the potential for a cluster development now exists."

The rig will now move to drill the Batu Hitam prospect, in PM308A, the third well in Lundin Petroleum's five well drilling campaign in Malaysia in 2011.

Lundin Petroleum holds a 75 percent interest in SB303 through its subsidiary Lundin Malaysia BV. Lundin Malaysia BV's partner is PETRONAS Carigali Sdn Bhd with a 25 percent interest.

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Thursday, July 28, 2011

Eni Hits Hydrocarbon Pay Offshore Ghana

- Eni Hits Hydrocarbon Pay Offshore Ghana

Thursday, July 28, 2011
Eni S.p.A.

Eni has made a new hydrocarbon discovery offshore Ghana through the Gye Nyame 1 well, which is located in the OCTP block 50 km off the Ghanaian shoreline.

The well, which was drilled in 519 meters of water, was drilled to a total depth of 3,349 meters and encountered significant thickness of gas and condensate sands with excellent reservoir characteristics. Oil mineralization was also discovered in the underlying sands. Its significant potential will be further assessed through a delineation program.

The discovery is located 16 km east of the Sankofa gas discovery, and confirms the important role of this block in the development of non-associated gas resources in Ghana.

Eni has already begun talks with the Ministry of Energy and the partner organization, GNPC (Ghana National Petroleum Corporation), aimed at fast-tracking the development of Sankofa which will contribute to the valorization of the gas on the domestic market, thus contributing to the ambitious growth targets of the country.

Thanks to the discovery of Gye Nyame, Eni can now also study important development and production synergies. By consolidating gas volumes of the two discoveries, this development opens up opportunities for exploiting the international market for liquefied gas, through offshore facilities of which Eni has significant knowledge and appropriate technology.

Eni, through its subsidiary Eni Ghana Exploration and Production Limited, is the operator of the OCTP license with a 47.22% interest. Other partners are Vitol Upstream Ghana Limited, with a 37.78% stake, and state company GNPC with a 15% stake. GNPC has a back-in option for an additional 5% of the license.

Eni is also finalizing the farm in to the Keta block as operator with a 35% stake. The block is located offshore the eastern coast of Ghana, bordering Togalese waters, where Eni acquired two exploration licenses in 2010. Partners in the Keta Block Joint Venture are Afren Energy Ghana Ltd., wholly owned subsidiary of Afren plc, with a 35% stake, Mitsui E&P Ghana Keta Ltd. with 20% and GNPC with 10%.

Eni has been present in Sub-Saharan Africa since the early 1960s and is currently operating in Angola, Nigeria, Togo, Ghana, Republic of Congo, Gabon, Democratic Republic of Congo and Mozambique. Eni's operated production in the area is around 450,000 barrels of oil equivalent per day.

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Tuesday, July 19, 2011

PA Resources Hits Gas Pay in Danish North Sea

- PA Resources Hits Gas Pay in Danish North Sea

Tuesday, July 19, 2011
PA Resources AB

PA Resources' subsidiary PA Resources UK Limited announced initial results of the Broder Tuck exploration well (5504/20-4), located approximately 10 kilometers south of Gorm Field in the Danish part of the North Sea.

Following some initial drilling problems, the well was drilled as a vertical well to a total depth of 3,658 meters below mean sea level in layers of Lower Jurassic/Triassic age.

The well encountered approximately 17 meters of net pay in high quality sandstones in the primary Middle Jurassic target. The reservoir was cored and an extensive wireline log, pressure and sample suite has been taken for future evaluation, with well site sample analysis showing the reservoir fluid to be gas with some condensate.

The Broder Tuck well has established a gross hydrocarbon column of at least 230 meters from the crest of the structure down to the base of the column encountered in the well. A sidetrack will now be drilled to assess the potential for additional gas volumes down-dip.

The following companies participate in Lenience 12/06: PA Resources UK Limited (64%), Nordsøfonden (Danish North Sea Fund) (20%), Danoil Exploration A/S (8%) and Spyker Energy APS (a wholly-owned subsidiary of Spyker Energy Plc) (8%).

Bo Askvik, President and CEO at PA Resources, commented, "We are delighted to have made this exciting discovery with our first operated well in the North Sea. I would like to congratulate our exploration/operations team on this outcome and to thank our partners for their continued support. We now look forward to the results of the sidetrack."

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Monday, July 18, 2011

Rocksource Hits Dry Well at Breiflabb Prospect

- Rocksource Hits Dry Well at Breiflabb Prospect

Monday, July 18, 2011
Rocksource

Rocksource ASA announced today that the drilling rig Borgland Dolphin is in the process of completing drilling operations on the "Breiflabb" prospect, in licence PL 416 in the Norwegian part of the North Sea. The well did not encounter hydrocarbons. The well will be further reviewed in the upcoming quarterly presentation on August 17th.

The PL 416 partnership consists of E.ON Ruhrgas (Operator and 50 per cent working interest), Det norske oljeselskap (15 per cent) and Rocksource (35 per cent).

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Chesapeake's Buffalo Creek Well Hits Production Milestone

- Chesapeake's Buffalo Creek Well Hits Production Milestone

Monday, July 18, 2011
Chesapeake Energy

Chesapeake Energy Corporation today announced its Buffalo Creek 1-17 well located in Beckham County, Oklahoma, recently surpassed cumulative gross production of more than 60 billion cubic feet of natural gas (bcf). Chesapeake operates the well with an 82.6% working interest and a 65.8% net revenue interest.

Chesapeake originally spud the well in May 2002 and reached a total depth of approximately 21,000 feet in the Cunningham Sand of the Deep Springer formation with first sales commencing in December 2002. The well averaged approximately 41 million cubic feet of natural gas (mmcf) per day for the first two years of production and is still producing approximately 8 mmcf per day.

Total gross capital expenditures to drill and complete the well were $8.5 million and subsequent operating expenses have been $1.4 million, or $0.024 per thousand cubic feet of natural gas equivalent (mcfe). Total gross revenue has been approximately $320 million, which includes approximately $65 million paid to royalty owners and approximately $15 million paid in severance tax to the state of Oklahoma. Total net cash flow from the well to the working interest owners has been approximately $230 million, or a multiple of 27 times the original cost of drilling and completing the well, and the realized price per mcfe has averaged $5.35.

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “The Buffalo Creek 1-17 has certainly been a special well in the history of Chesapeake. As early pioneers drilling deep conventional wells using 3-D seismic in the Anadarko Basin, the success of the Buffalo Creek 1-17 well initiated a process almost 10 years ago that has now led to Chesapeake owning the largest leasehold position in the Anadarko Basin. This industry-leading leasehold position has proved to be exceedingly valuable as unconventional plays such as the Granite Wash, Cleveland and Tonkawa plays have emerged in areas in and around our traditional strongholds of conventional Anadarko Basin production. We believe that this is only the sixth well in Oklahoma history to reach this remarkable milestone of 60 bcf of cumulative production and Chesapeake now operates four of the six most prolific natural gas wells ever drilled in Oklahoma. I offer my congratulations to the entire Chesapeake Anadarko Basin team for being part of this historic well.”

McClendon added, “As a result of this well’s success and the many other successful Deep Springer wells we have drilled in the Anadarko Basin over the years that followed the drilling of the Buffalo Creek 1-17, we continue to pursue ultra-deep 3-D based Deep Springer drilling in the Anadarko Basin and we are currently operating three rigs in the play, where we believe at least another 185 wells can be drilled in the years ahead on our approximate 75,000 net acres of Deep Springer leasehold.”

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Friday, July 8, 2011

Lundin Hits Gas Pay in Barents Sea

- Lundin Hits Gas Pay in Barents Sea

Friday, July 08, 2011
Lundin Petroleum AB

Lundin, operator of production license 438, has completed well 7120/2-3S on the Skalle prospect as a gas discovery. A comprehensive logging and coring program has been acquired.

The well is situated approximately 25 kilometers north of the Snohvit Field in the south western part of the Barents Sea. The primary target for the well was to prove hydrocarbons in reservoir rocks from both the Cretaceous and the Jurassic age. Gas was proven in three separate zones.

The initial gross contingent resource range for the Skalle discovery is estimated at between 88 to 280 billion cubic feet (bcf) (15 to 50 million barrels of oil equivalent (MMboe)). There is a potential for a deeper oil leg in the lower Cretaceous reservoir of Skalle and an upside potential in Skalle substructures.

The results of the well will be further analyzed to determine the appraisal program for the discovery.

Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "The Skalle gas discovery is close to existing infrastructure with upside potential both in nearby substructures and other prospects on the license. We remain confident regarding the oil prospectivity of Lundin Petroleum's Barents Sea acreage."

The well 7120/2-3S is the first exploration well in PL438 and was drilled to a vertical depth of approximately 2,600 meters below sea level.

Well 7120/2-3S was drilled using the rig Transocean Leader, which now will move to PL265 in the Greater Luno Area in the Norwegian North Sea to drill the Aldous Major South exploration well 16/2-8. Statoil ASA is the operator of PL265 and Lundin Petroleum has a 10 percent interest.

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Friday, July 1, 2011

OGX Hits Hydrocarbon Pay in Santos Basin

- OGX Hits Hydrocarbon Pay in Santos Basin

Friday, July 01, 2011
OGX S.A.

OGX has identified the presence of hydrocarbons in the Santonian section of 1-OGX-47-RJS well, in the BM-S-59 block, in the shallow waters of the Santos Basin. OGX holds a 100% working interest in this block.

"This discovery in conventional reservoirs of the Santos Basin contributes significantly to the development of our assets in this region. When combined with the discoveries that we have already made, we will be able to optimize the operational structure of this area by taking advantage of the economies of scale," commented Mr. Paulo Mendonça, General Executive Officer and Exploration Officer of OGX. "Following the drilling campaign, we will intensify both the appraisal process of the several discoveries for this basin, as well as the development of the production model for the region," added Mr. Mendonça.

A hydrocarbon column of approximately 131 meters was encountered in the sandstone reservoirs of the Santonian section with about 51 meters of net pay. This discovery is located 2.9 kilometers from the Natal accumulation which was discovered through the drilling of well OGX-11.

The OGX-47 well, named as Maceió, is located in the BM-S-59 block and is situated approximately 110 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 185 meters. The Ocean Quest rig initiated drilling activities on May 24, 2011.

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Thursday, June 30, 2011

Beach Hits Oil Pay at Parsons-5

- Beach Hits Oil Pay at Parsons-5

Thursday, June 30, 2011
Beach Energy Ltd.

Beach Energy Ltd. announced Thursday that it has successfully encountered a six-meter oil column at the Parsons-5 development well in the Cooper Basin Western Flank.

Beach had its fifth success in its PEL 92 drilling program with two wells remaining to be drilled. The Parsons-5 well, located 1.3km south of the Parsons-1 discovery well, encountered a six meter oil column.

The Parsons-5 oil column was encountered in the Namur Sandstone reservoir and was consistent with pre-drill expectations. The confirmed updip position with respect to Parsons-2 will result in an upgrade of recoverable oil reserves from the Parsons Field.

Beach will announce a firmer reserve assessment as appropriate data becomes available, but preliminary work suggests that well results from the current drilling program, plus continued strong production performance, will result in an reserve increase in excess of 800,000 barrels for the Parsons Field.

Parsons-5 is expected to be tied in during the second half of the year through the Parsons oil facility. Oil from the Parsons Field is transported from the Western Flank by flowline to Tantanna, from where it is currently trucked to Moomba, and hence not impacted by any flooding in the area.

The next well to be drilled in the PEL 92 program will be the Wheatons-1 exploration well, which is located about 10km to the north of the Parsons Field. Participants in PEL 92 are:
  • Beach (Operator) 75%
  • Cooper Energy Limited 25%

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Wednesday, June 22, 2011

Reliance Hits Gas Pay Offshore India

- Reliance Hits Gas Pay Offshore India

Wednesday, June 22, 2011
Hardy O&G plc

Hardy O&G announced its first gas discovery in the exploration well KG-D9-A2 within the D9 license.

The well KGD9-A2 was drilled to a total depth of 4,881 m MDRT with the objective of exploring the play fairway in the Early and Late Miocene Channel Levee Complex in a water depth of approximately 2,700 m. Three sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT. This discovery, named 'Dhirubhai - 54' has been notified to the Government of India and DGH. The potential commerciality of this discovery is being ascertained through more data gathering and analysis. This play fairway is expected to cover a considerable area within the block.

The D9 exploration license is located in the Krishna Godavari (KG) Basin on the east coast of India and presently covers an area of approximately 8,695 km2. Hardy holds a 10 percent participating interest in the license which is operated by Reliance Industries Limited. The license's minimum work program provides for the drilling of four exploration wells.

Commenting on the well results, Yogeshwar Sharma, Chief Executive Officer of Hardy said, "We are encouraged by this discovery which extends the proven Miocene play fairway into the frontier D9 block. The discovery further enhances our understanding of the block's petroleum systems and reinforces our enthusiasm for unlocking its hydrocarbon potential. The D9 joint venture expects to drill the fourth exploration well prior to the end of 2011."

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Wednesday, June 15, 2011

Coastal Hits 'Significant' Oil Pay at Bua Ban

- Coastal Hits 'Significant' Oil Pay at Bua Ban

Wednesday, June 15, 2011
Coastal Energy Co.

Coastal announced that the Bua Ban North B-06 well was drilled to a total depth of 6,800 feet TVD and encountered 69 feet of net pay with 28 percent porosity in the Miocene interval. MDT (Modular Dynamic Testing) pressure analysis confirms that the well is in communication with the B-02 and B-04 wells and oil samples recovered have an API gravity of 36 degrees.

The B-06 also encountered 17 feet of net pay with 22 percent porosity in the Eocene in the western upthrown fault block, which has also been referred to as the Bua Ban North Terrace. This is the highest porosity Eocene pay zone that has been encountered in the basin.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "We are pleasantly surprised with the results of the B-06 well. The well was expected to encounter a wet section of the reservoir and be used for aquifer support; however, the fact that it encountered a significant oil pay zone in the Miocene which is connected to the other wells in the same fault block has several positive implications.

The lowest known oil in this fault block has been moved lower by 100 feet and has nearly tripled the extent of the structural closure to 425 acres. The oil water contact here is much deeper than originally anticipated. Following this discovery, we will drill an additional well (B-07), to confirm the MDT data which indicate an oil water contact at 3,825 feet. The B-07 well can be used for water injection. We then plan to drill a well (B-08) on the eastern side of the field and northeast of the B-03 well to further evaluate the full extent of this closure. If successful, this would materially increase the size of the productive field.

In addition, the high quality of the Eocene reservoir which was seen confirms our assessment that the Eocene is conventionally producible above 6,500 feet. The B-06 well supports further exploration to the north and west and reduces the risk of the Company's Eocene targets.

The mobile offshore production unit is on standby and will mobilize to Bua Ban North B to begin testing operations as soon as the drilling rig moves off location."

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Monday, June 13, 2011

Harvest Natural Hits Oil Pay Offshore Gabon

- Harvest Natural Hits Oil Pay Offshore Gabon

Monday, June 13, 2011
Harvest Natural Resources Inc.

Harvest Natural Resources has encountered oil in the wildcat well Dussafu Ruche Marin-1 (DRM-1) drilled in the Dussafu Marin PSC, in the offshore waters of Gabon, West Africa. Harvest operates the Dussafu PSC, holding a 66.667 percent interest. The well was spudded on April 28 and is being drilled to test the potential of the pre-salt Gamba and Dentale Formations.

Drilled with the Transocean Sedneth 701 semi-submersible drilling unit in 380 feet of water, the DRM-1 well has reached a vertical depth of 9,953 feet within the Upper Dentale Formation. Log evaluation, pressure data and samples indicate that Harvest has discovered approximately 55 feet of pay in a 90 foot oil column within its primary objective, the Gamba Formation.

Additional technical evaluation will be required to appraise this Gamba discovery. Forward plans include deepening the well to test Middle and Lower Dentale exploration potential and sidetracking to appraise the extent of the Gamba oil discovery.

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Wednesday, May 25, 2011

Santos Hits Oil Pay at Finucane South

- Santos Hits Oil Pay at Finucane South

Wednesday, May 25, 2011
Santos Ltd.

Santos has announced an oil discovery at Finucane South in the Carnarvon Basin, offshore Western Australia. Well logs and wire line testing have confirmed a net oil column of 18 meters in excellent quality reservoir sands in the Angel Formation. The well was drilled using semisub Stena Clyde.

The Finucane South oil discovery is located approximately 7 kilometers from the Fletcher oil field discovered in 2009 and approximately 14 kilometers from existing oil production facilities at Mutineer Exeter. Both Finucane South and Fletcher are located within WA-191-P.

Engineering studies for a dual field development of the Finucane South and Fletcher discoveries are well advanced, with the WA-191-P participants expected to be in a position to make a final investment decision before the end of 2011.

A number of development options have been considered, including a sub-sea tie back to the Santos operated floating production, storage and offloading facility servicing Mutineer Exeter. This would enable first oil production from Finucane South and Fletcher by the end of 2013.

Santos Vice President Exploration and Subsurface Trevor Brown said the Finucane South result was on the high side of pre-drill expectations and is another valuable discovery for Santos following the Zola gas discovery in April this year.

Santos Vice President WA & NT John Anderson said Finucane South when combined with Fletcher would allow the WA-191-P partners to progress an oil development with an exceptionally quick cycle time to first oil production.

The well will be suspended after finalization of the evaluation program.

Santos holds a 33.4% interest in WA-191-P and is operator. Other participants are Kufpec Australia (33.4%), JX Nippon Oil & Gas Exploration Corporation (25%) and Tap Oil (8.2%).

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Tuesday, May 10, 2011

Coastal Hits Pay Offshore Thailand

Coastal Hits Pay Offshore Thailand

Tuesday, May 10, 2011
Coastal Energy Co.

Coastal Energy Co. on Tuesday announced the successful results of the Bua Ban North B-02 exploration well.

The Bua Ban North B-02 well was drilled to 6,513 feet TVD and encountered 62 feet of net pay in the Miocene objective with 26% average porosity. The B-02 well also tested the Eocene interval and encountered 150 feet of net sand with 19% average porosity. The Eocene sand zone was wet as it was not a target in this well and was drilled off structure.

The B-02 has been cased and suspended pending the arrival of testing equipment. Conductor pipe has been set on the B-03 well, which is testing the Miocene in a separate fault block due east from the B-02 well.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented:

"The B-02 well encountered thicker sands in the Miocene than were anticipated with better than expected reservoir quality. The Eocene zone which was encountered was not a target in this well, but delivered the highest reservoir quality sands we've seen to date in the Eocene interval. The reservoir characteristics in the Eocene are better than what we have modelled at this depth. This supports our thesis of higher quality sands in the shallower Eocene and should bode well for the planned drilling of the shallower Eocene prospects to the northwest."

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Friday, May 6, 2011

N.D. Hits Oil Tax Revenue Milestone

N.D. Hits Oil Tax Revenue Milestone

Friday, May 06, 2011
The Bismarck Tribune, Bismarck, North Dakota
by Rebecca Beitsch, The Bismarck Tribune, N.D.

Instability in the Middle East is one of the contributing factors for a record-breaking month for oil tax revenue in North Dakota.

This is the first time the state has surpassed a $100 million benchmark for tax revenue, thanks to production in March, the most recent data available.

From November 2010 to February of this year, oil has brought in tax revenues hovering around $80 million, but in March that number rose to more than $100 million for the first time.

That brought in $20 million more than in February despite a drop in production of about 2,000 barrels.

The lower production levels didn't affect tax revenue because the taxation formula also relies on the price of crude. That rose about $14 between February and March to rest at $92 a barrel.

Rioting in Egypt in late January followed by a civil war in Libya starting in February and protests in Bahrain in March have all combined to take a toll on the price of oil, which is traded in a global market.

"The market is very sensitive to any kind of unrest like that. It's true that Libya has significant production, but it isn't to the extent that it couldn't be made up somewhere else," said Deputy Tax Commissioner Ryan Rauschenberger, adding that the price swings could be more of an emotional reaction as most Libyan oil isn't imported to America.

"It's more about the unrest than exactly where those barrels were going, and can Saudi Arabia pick up the slack? I think it has more to do with just the fact that it's in a region that supplies such a great deal of the world's oil," Rauschenberger said.

Patrick DeHaan, a petroleum analyst for the website GasBuddy.com, agreed with that interpretation, saying price increases are "very much an emotional reaction."

"The U.S. got 2 million barrels of oil from Libya in December 2010, compared with 34 million from Saudi Arabia," DeHaan said.

He said an increased risk of seeing a change in production is the underlying factor, but there are hundreds of aspects that impact the price of crude oil.

DeHann pointed to a weak U.S. dollar along with a slowly improving economy that has people driving more and creating a greater demand for oil.

Other factors in North Dakota's crude oil price are its quality, but also it's difficulty in accessing refining markets.

"This is top shelf crude oil," said Ron Ness, president of the North Dakota Petroleum Council. He said it's valuable because it can be used for a variety of products, is easy to blend with other types of oil and is just more easily processed than some other types of crude.

What keeps the price lower than it should be is that it is hard to get to market, something Ness said requires knocking 10 percent off the price.

As for the production, Kathy Strombeck, an analyst with the tax department, said levels have been steadily increasing over the past several months because of technology, and more recently, warmer weather.

"Are we producing more oil in North Dakota because of the Middle East unrest? Probably not. We're producing it because of the technology, the leasing, because of the good environment with the business climate here, all those things are why we're producing more oil," Strombeck said. "So there are two reasons North Dakota's oil revenues are doing well. One is certainly the higher price and the other is production."

Strombeck said in the short term she expects several more $100 million-plus months.

Copyright (c) 2011, The Bismarck Tribune, N.D. Distributed by McClatchy-Tribune Information Services.

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Thursday, May 5, 2011

Woodside Hits Oil Pay at Laverda North

Woodside Hits Oil Pay at Laverda North

Thursday, May 05, 2011
Woodside Petroleum Ltd.

In April 2011, the Laverda North-2 appraisal well was drilled and discovered a gross interval of 18 meters of new oil-bearing sands. Wireline sampling from the new zone recovered more than 20 liters oil to the surface.

As expected, the well also intersected a gross interval of about 10 meters of oil-bearing sands in the Laverda oil field, which was discovered by Woodside in 2000.

Preliminary evaluation is progressing and now suggests that the combined volumes of the Greater Laverda area have the potential to contain a recoverable volume in excess of 100 million barrels of oil (100% basis).

Additional work is required in order to confirm the ultimate size of the accumulations. Appraisal drilling and analysis, plus further geological and reservoir modeling is expected to be conducted to refine this volume.

Laverda North-2 was a planned sidetrack to the Laverda North-1 appraisal well. It was drilled to a total depth of 2,300 meters (measured depth).

The Greater Laverda area is located in WA-36-R in Western Australia's Exmouth sub-basin, about 10 km west of the Woodside-operated Enfield oil project. Woodside also has interest in the nearby Vincent and Stybarrow oil projects.

Woodside is the operator and 60% equity owner of WA-36-R with Mitsui E&P Australia Pty Ltd holding the remaining 40% interest.

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Friday, April 29, 2011

Coastal Energy Hits Net Pay at Bua Ban North

Coastal Energy Hits Net Pay at Bua Ban North

Friday, April 29, 2011
Coastal Energy Co.

Coastal Energy announced the successful results of the Bua Ban North B-01 exploration well.

The Bua Ban North B-01 well was drilled to 7,960 feet TVD and encountered 28 feet of net pay in the Upper Oligocene with 23% average porosity and 29 feet of net pay in the Lower Oligocene with 16% average porosity. Net pay estimates are based on log analysis, shows and MDT analysis; the well has not been flow tested. The Company estimates that this fault block contains a total of 13 million barrels of oil in place across these two intervals.

The B-01 well also encountered good oil shows in three zones in the Miocene; however, this interval was not targeted in this well and the Miocene was not encountered in an optimal structural position. There was also an oil show in the Eocene interval.

The Company has spudded the Bua Ban North B-02 well, which will test two Miocene intervals in an optimal structural position. The B-02 well will also test Oligocene and Eocene targets. Although high gas readings were encountered throughout the Eocene and an oil show was observed, the top of the Eocene reservoir was penetrated at 7170 feet, below our interpreted threshold for development of reservoir quality sands.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The B-01 well delivered positive results for the Bua Ban North B prospect. We saw good oil shows throughout all of our targeted intervals which support further drilling to test the Miocene and Eocene intervals at this location. The shallow shows continue to support the potential for shallower Miocene and Upper Oligocene targets along the entire western margin of the Songkhla basin. The Eocene interval is predicted to be of reservoir quality at 6,500 feet and shallower; it was encountered in this well at 7,170 feet. We plan to test Eocene targets further up the terrace at shallower depths.

"The drilling results from Bua Ban North continue to be positive. We also remain on target to begin production testing of the multiple discoveries at Bua Ban North A in mid-May."

Randy Bartley, President and Chief Executive Officer of the Company and a member of the Society of Petroleum Engineering and Jerry Moon, Vice President, Technical & Business Development, a member of the American Association of Petroleum Geologists, a Licensed Professional Geoscientist and a Certified Petroleum Geologist in the state of Texas, have reviewed the contents of this announcement.

Monday, April 25, 2011

Ecopetrol Hits Hydrocarbons in Huila Province

Ecopetrol Hits Hydrocarbons in Huila Province

Monday, April 25, 2011
Ecopetrol S.A.

Ecopetrol has found the presence of hydrocarbons in the Nunda-1 well, located in the municipality of Tello in Huila province.

The well is part of the Cuisinde Exploration and Exploitation Agreement of 2006 between Ecopetrol and the National Hydrocarbons Agency, ANH in which the company holds a 100% stake.

Drilling at the well began on January 27, 2011, reaching a total depth of 7,371 feet three weeks later, the equivalent of 2.25 kilometers from the surface.

Preliminary testing on the Honda formation showed a flow volume of 318 barrels, with a 71% water cut, yielding an average of 92 barrels of oil per day. The quality of the crude is 30 degrees API.

Ecopetrol will begin appraising the find in the weeks ahead, with extensive tests planned in order to determine the production potential of the Honda formation and the volume of recoverable hydrocarbons.

The discovery opens up a new era for Ecopetrol by branching out to new types of exploration activities involving stratigraphic traps (those in which hydrocarbons accumulate due to variations in the deposit environment) in the Valle Superior del Magdalena and helps increase reserve inventories in this area of the country.