Cooper to Plug and Abandon Perlubie-2 Well

- Cooper to Plug and Abandon Perlubie-2 Well

Thursday, August 25, 2011
Cooper Energy Ltd.

Cooper announced that the Perlubie-2 appraisal/development well has been drilled to a total depth of 1366 mRT and wireline logs have been run and interpreted.

Perlubie-2 has encountered the Namur sandstone reservoir low to prognosis and logging has confirmed an oil column in Namur and McKinlay Member sandstone reservoirs. Due to the small height of the oil column, the well is not expected to recover sufficient oil to justify a completion and tie-in to the production system and therefore the PEL 92 JV has decided to plug and abandon the well.

The rig will be moved to Germein-1 well location as the next exploration well.

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Cairn to Abandon Well Offshore Greenland

- Cairn to Abandon Well Offshore Greenland

Wednesday, August 03, 2011
Cairn Energy

The following operational update relates to Cairn Energy's exploration drilling campaign offshore Greenland.

LF7-1 Well: Lady Franklin Block, South Ungavva Area

The LF7-1 exploration well, located in 1,002 meters (m) of water approximately 300 kilometers (km) offshore Nuuk, has reached target depth (TD) in basement strata and preparations are under way to plug and abandon the well. The well encountered a thick Upper Cretaceous section with tight (cemented) sandstones although the anticipated stratigraphically deeper reservoir section was absent at this location. Initial geochemical analysis of the background gas composition indicates the presence of pre-Tertiary oil prone source rocks in the basin.

The Ocean Rig Corcovado is currently carrying out abandonment operations on the LF7-1 well.

AT7-1 Well: Atammik Block, South Ungavva Area

The AT7-1 exploration well in the Atammik Block, located in 909m of water 200km offshore Nuuk, has been temporarily suspended by the Leiv Eriksson. The AT7-1 well is currently suspended above the prognosed target objectives and the well is scheduled to be re-entered and drilled to planned TD at a later date in the current program. With the opening of the weather window in the Disko area the Leiv Eriksson was moved 750km north to commence operations on the Delta prospect in the Napariaq Block, optimizing the program.

Delta-1 Well: Napariaq Block, West Disko Area

The Delta-1 well has spudded on the Delta prospect, located in a water depth of 293m approximately 100km off the Greenland coast and 110km northeast of the Alpha-1S1 well drilled by Cairn in the Sigguk Block in 2010.

Gamma Prospect: Eqqua Block, West Disko Area

The Gamma prospect in the Eqqua block, located in 1,520m of water and 110km southwest of the Alpha-1S1 well is scheduled to be drilled using the Ocean Rig Corcovado after operations on LF7-1 are complete.

A further update will be provided whenever a well is at TD and operations are complete.

Simon Thomson, Chief Executive, said, "Although no reservoir has been found in the LF7-1 well, the first in the basin, we are encouraged by further indications of pre-Tertiary oil-prone source rocks across our Greenland acreage. The exploration challenge remains to find the reservoir sands. We continue to be optimistic about the remainder of our 2011 four-well, multi-basin exploration program offshore Greenland."

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Cobalt to Abandon Angola Well, Updates GOM Ops

- Cobalt to Abandon Angola Well, Updates GOM Ops

Wednesday, July 27, 2011
Cobalt International Energy Inc.

Cobalt announced a net loss of $19.5 million, or $0.05 per basic and diluted share for the second quarter of 2011, compared to a net loss of $41.8 million, or $0.12 per basic and diluted share, for the second quarter of 2010.

Cash expenditures (excluding changes in working capital) for the quarter ended June 30, 2011 were approximately $22 million and about $33 million year-to-date. For the full year 2011, Cobalt expects to spend $325 to 400 million which includes the cash expenditures associated with Block 20 offshore Angola. The timing of expenditures in the second half depends primarily on when the Block 20 Production Sharing Agreement is signed and when Cobalt recommences Gulf of Mexico drilling activities.

Cash, cash equivalents and investments at the end of the second quarter were approximately $1.64 billion. This includes about $339 million designated for future operations held in escrow and collateralizing letters of credit, but excludes approximately $196 million in the TOTAL drilling fund for the Gulf of Mexico. Cobalt expects it is well-funded to execute on its planned exploration and appraisal program, including expenditures relating to Block 20 offshore Angola, through the end of 2013.

Operational Update

On April 15, 2011, Cobalt completed a registered underwritten offering of 35,650,000 shares of its common stock at a public offering price of $14.00 per share, resulting in proceeds of approximately $499 million before expenses.

On May 3, 2011, Cobalt announced that the national oil company of Angola, Sociedade Nacional de Combust•veis de Angola-Empresa Publica (Sonangol), had approved Cobalt's drilling plans for its two initial pre-salt exploratory wells, Bicuar #1 and Cameia #1, on Block 21 offshore Angola. Subsequent to the end of the second quarter, on July 19, 2011, Cobalt commenced its initial two well pre-salt exploratory drilling program on Block 21 offshore Angola by spudding the surface hole of the Bicuar #1 exploratory well. On July 20, 2011, after setting the 36" conductor casing and drilling approximately 210 meters of surface hole, Cobalt encountered an over pressured water sand resulting in a water flow with limited quantities of natural gas. No safety or environmental issues resulted from the incident. Cobalt is focused now on its abandonment procedures for the Bicuar #1 exploratory well surface location. Given the unique nature of encountering pressured water sands in Angolan waters, Cobalt has agreed with Sonangol that Cobalt will take its learnings from this incident and reexamine its shallow hazard analysis of proposed Cameia and Bicuar drilling locations before moving the drilling rig to Cameia or a different surface location on Bicuar.

With respect to Cobalt's U.S. Gulf of Mexico drilling program, Cobalt believes it has satisfied all of the remaining requirements of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) related to its North Platte #1 and Ligurian #2 applications for permit to drill (APD's), except for the submission of the U.S. Coast Guard Certificate of Compliance for the Ensco 8503 drilling rig, which cannot be obtained until the rig returns to the U.S. Gulf of Mexico. Cobalt does not anticipate any issues related to obtaining this routine U.S. Coast Guard certification and it expects that after its submission the BOEMRE will promptly issue the APD's for both the North Platte #1 and Ligurian #2 exploratory wells. Cobalt expects that the Ensco 8503 drilling rig will be returned to Cobalt in the U.S. Gulf of Mexico late in the third quarter of 2011. Upon its return, the submission of the U.S. Coast Guard Certificate of Compliance, and the issuance of the APD's for the North Platte #1 and Ligurian #2 exploratory wells, Cobalt plans to drill the Ligurian #2 exploratory well. After drilling the Ligurian #2 exploratory well, Cobalt plans to move the rig to the North Platte #1 well location to drill that prospect. Cobalt anticipates that each of the Ligurian #2 and North Platte #1 exploratory wells will take approximately six months to drill.

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Cooper to Abandon Wheatons-1 Well

- Cooper to Abandon Wheatons-1 Well

Friday, July 15, 2011
Cooper Energy Ltd.

The Wheatons-1 exploration well has been drilled to a total depth of 1882 mRT and wireline logs have been run and interpreted, according to Cooper Energy.

During drilling there were no hydrocarbon shows observed in the primary objective (Namur Sandstone) or secondary objectives (Birkhead, Hutton and Poolowanna Formations) and the evaluation of the wireline logs has confirmed the absence of hydrocarbons in all objective horizons.

The Wheatons-1 well will be plugged and abandoned as a dry hole. Preparations are in place to move the rig to the Rincon-1 drill site.

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Sterling to Plug, Abandon Sangaw North Well

- Sterling to Plug, Abandon Sangaw North Well

Wednesday, July 06, 2011
Sterling Energy plc

Sterling provided the following update for the Sterling operated Sangaw North block in Kurdistan (53.33% working interest).

Flow testing operations have been completed in the cased hole section of the Sangaw North-1 well. Two flow tests were conducted; the first across a 100 meter interval within the Jurassic aged Sargelu formation and the second across a 100 meter interval within the Cretaceous aged Kometan formation.

During the first flow test, formation gas and water were observed in small quantities at surface but sustainable flow rates were not achieved. The Company believes that the Jurassic aged Sargelu formation does not contain a sufficient natural fracture network to support sustained flow.

During the second flow test, within the Cretaceous aged Kometan formation, the well flowed at a stabilized rate of approximately 0.4 million standard cubic feet of gas and 4,500 barrels of formation water per day during an 8 hour flow period through a 60/64ths inch choke with a wellhead pressure of 280 pounds per square inch. Approximately 83 percent of the produced gas was hydrocarbon gas with the remainder comprising 10 percent hydrogen sulphide and 7 percent carbon dioxide.

Neither flow test produced hydrocarbons at commercial rates and the Sangaw North-1 well will now be plugged and abandoned. The operations to plug and abandon the well are expected to take approximately 2 weeks, after which the drilling rig will be demobilized from the location.

The current exploration phase of the Production Sharing Contract for the Sangaw North area will expire in November 2011 and the joint venture partnership (Sterling, Addax and KNOC) may elect to enter the next exploration phase which runs until November 2013; the Sangaw North-1 well has fulfilled the work commitment for this next phase. During the coming months Sterling will integrate and analyse the seismic, drilling, logging and testing data before making recommendations to the joint venture group.

Angus MacAskill, Sterling's Chief Executive said, "We are disappointed that flow testing has not demonstrated commercial hydrocarbon flow rates in the Sangaw North-1 well. An integrated interpretation of all the data acquired during well operations will be conducted to determine the remaining potential of the Sangaw North structure prior to a decision on future operations."

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Icon to Abandon Lydia Well

- Icon to Abandon Lydia Well

Tuesday, June 21, 2011
Icon Energy Ltd.

Icon announced that the current drilling operations in the ATP626P Lydia Block have come to a conclusion with the joint venture making a decision to plug and abandon the Lydia-13 well.

The decision to plug and abandon the well was made following an assessment that the coal permeability was insufficient to warrant economic gas production from the well.

The well was drilled to a total depth of 825 meters, and was cored and tested.

Lydia-13 was the last well in the four well drilling program in ATP626P for the current budget year ending June 30, 2011. Subject to board and joint venture partner approval, a following drilling program is expected to commence in the new budget year beginning July 1, 2011. This program would be located in the most promising areas found so far and not necessarily restricted to the farmin area.

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Chevron to Abandon Shetland Well

- Chevron to Abandon Shetland Well

Monday, June 13, 2011
Faroe Petroleum plc

Faroe announced that drilling has reached target depth on the Lagavulin exploration well (Faroe 10%), operated by Chevron, in the UK Atlantic Margin to the west of the Shetland Islands.

Well 217/15-1z, on the Lagavulin prospect was spudded in October 2010 and drilled in 1,567 meters water depth. Total depth was reached on June 10, 2011. Hydrocarbons and a working petroleum system have been confirmed, however no workable reservoir system was found to be present at this location and the well will be plugged and abandoned. Extensive data gathering has been undertaken in the well and detailed analysis is underway to fully evaluate the well results.

The well was drilled with the Stena Carron drillship. Progress was slower than expected, principally due to a number of operational and technical challenges, notably poor weather conditions and variable drilling formation. As a result of these delays, the cost of this well was greater than projected.

Faroe Petroleum has, since its formation in 1998, been at the forefront of basalt exploration in the Atlantic Margin, in partnership with several Major oil companies, including Chevron, BP, Eni and Statoil. The material potential the region offers continues to attract super-Majors such as Exxon, who joined with Statoil earlier this year in committing to further sub-basalt drilling in the Atlantic Margin region in the coming period. The results of the Lagavulin exploration well will significantly advance our understanding of the geology and ability to unlock the high potential basalt play in the Atlantic Margin region.

The Company pursues a portfolio exploration business model, which is managed to mitigate the negative impact that any single well can have on our continuing well program. Among the fully-funded 17 firm and expected wells in our schedule to end 2013, the Company is participating in two further near-term high impact exploration wells in the west of Shetlands area, namely the shallow water Fulla well, in which Faroe holds a 50 percent interest, and the deep water North Uist well. The first of these to be drilled, Fulla, is located close to the producing Clair oil field, in shallow water and is expected to commence in June, with Faroe as operator, while North Uist is now expected to be drilled in early 2012. Furthermore, three wells are scheduled to spud in Norway in the coming months: Butch and T-Rex in August and Kalvklumpen in October. T-Rex will be Faroe's third well on the Halten Terrace, in the same area in which the Company made the two discoveries, Maria and Fogelberg, in 2010.

Graham Stewart, Chief Executive of Faroe Petroleum, commented, "Lagavulin was a true high risk frontier exploration well, offering material upside in a success case. While the outcome of the well is a disappointment, the presence of hydrocarbons has however now been proven and offers encouragement to continue our deep water exploration plans in the region."

"The Group is well funded and, despite the cost over-run on Lagavulin, none of our forward drilling program will be impacted. Faroe has a healthy cash balance and strong cash flows from our portfolio of production assets, with group production expected to be approximately 9,000 barrels of oil equivalent per day (boepd) by the year end. Furthermore, it should be noted that, following the recent completion of our Blane acquisition, the proceeds from sale of its accumulated oil inventory resulted in a significant unbudgeted windfall gain by the Company which more than offsets the cost over-run on Lagavulin."

"From an operational standpoint, Lagavulin was a deep and complex well, with no neighboring drilling history, and it was drilled safely by the partnership led by Chevron. A great deal has been learned from this well, which will serve to significantly reduce the cost of any future wells in the region. As we now proceed to analyze the data from the well, our exploration program continues on apace through 2011 and beyond, as we test our considerable portfolio, which currently has a 17 well, fully funded program, offering very material upside potential."

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Premier to Plug, Abandon Well at Vietnam Block

Premier to Plug, Abandon Well at Vietnam Block

Thursday, April 28, 2011
Pan Pacific Petroleum NL

Premier Oil Vietnam South B.V. ("Premier"), the operator of the Block 07/03 Production Sharing Contract, has advised that the CRD-2X-ST appraisal well operations have been successfully completed and that the CRD-2X well will now be plugged and abandoned as planned.

The CRD-2X appraisal well was spudded by the semi-submersible drilling rig the Ocean General on Thursday, February 10. The well was planned to evaluate the oil and gas discovered in multiple stacked Miocene and Oligocene reservoir sands by CRD-1X in 2009 with the aim of reducing uncertainty in whether the CRD (Cá Rong Ðo) structure contains sufficient volumes to support a potential development. CRD-1X tested two zones in the Miocene sands which flowed oil at a combined rate of 3,265.4 BOPD plus 8.1 MMSCFD, through a 48/64" choke, with no water. However, it was not possible to flow test the Oligocene sands at that time.

CRD-2X reached a total depth of 3,785 m BRT on March 10, and following evaluation of the section by logging, drill stem tests of two
reservoir zones in the Oligocene section were conducted. The first zone tested flowed gas and condensate at rates of 9.7 MMSCFD and 870 BOPD respectively through a 40/64" choke. The second zone tested flowed gas and condensate at rates of 17 MMSCFD and 1730 BOPD respectively through a 56/64" choke. The total net condensate/gas pay in this well was 72m, a significant increase compared with the 17 m of net pay penetrated in the Oligocene section in the up dip CRD-1X well.

CRD-2X was subsequently sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands. This sidetrack well CRD-2X-ST reached its planned total depth of 3,340 m BRT in the Miocene section and intersected 18.3m of net oil pay in the Miocene sands. This compares with 34.4m of net oil pay intersected in the Miocene section in the up dip CRD-1X well, and 3.8m in the down dip CRD-2X well.

These well results, including strong flows from the Oligocene sands have provided important information that will assist in the assessment of the resource potential of the CRD structure. The Operator will now undertake further studies to determine the feasibility of a commercial development.

Partners in the Vietnam Block 07/03 are:

• Pan Pacific Petroleum (Vietnam) Pty Ltd 5% (a wholly owned subsidiary of Pan Pacific Petroleum NL)
• Premier Oil Vietnam South B.V. (Operator) 30%
• Vietnam American Exploration Company, LLC. 40% (a wholly owned subsidiary of Pitkin Petroleum Plc)
• PearlOil (Ophiolite) Ltd. 15%
• PetroVietnam Exploration and Production Corporation Ltd 10%

Groundstar to Abandon Guyana Well

Groundstar to Abandon Guyana Well

Monday, April 25, 2011
Groundstart Resources Ltd.

Groundstar provided the following update on drilling and testing activities at the Apoteri K-2 exploration well located in the Takutu Basin of Guyana.

On April 20, 2011 the measured drill depth of the well reached 2,992 meters. The top of the Manari was encountered at 2,402 meters, 210 meters high to prognosis; the top of the Apoteri was encountered at 2,431 meters, 281 meters high to prognosis. At 2,517 meters an unexpected down to the southeast fault was encountered which significantly shortened the Manari section to a thickness of 29 meters compared to a thickness of 118 meters at the Karanambo-1 discovery well drilled by Home Oil in 1982. The fault also caused the Apoteri Volcanics to be encountered much higher than prognosed. Elevated gas readings (C1-C5) and oil shows were identified at various intervals in the Manari and Apoteri. A full suite of logs were run to 2,593 meters. The FMI (Formation Micro Image) log identified numerous fracture swarms in the Manari and Apoteri.

Based upon the gas and oil shows and log interpretation, drill stem tests (DSTs) have been conducted to date as follows in measured depths:

• DST 1 (Manari-Apoteri): 2,445 to 2,571 meters, misrun;
• DST 2 (Manari-Apoteri): 2,445 to 2,571 meters, recovered 20 meters drilling mud, reservoir was tight;
• DST 3 (Apoteri): 2,656 to 2,799 meters, recovered 73 meters drilling mud from low permeability reservoir;
• DST 4 (Apoteri): 2,897 to 2,991 meters, recovered 2,300 meters of formation salt water from a high permeability fracture zone at 2,976 meters.

Although excellent reservoir quality was encountered in this interval of the Apoteri Formation, the reservoir appears to have been penetrated below the oil – water contact, defined by the interval of good oil and gas shows between 2,515 and 2,841 meters.

Over the course of the next week the Apoteri K-2 well will be abandoned. The consortium is currently evaluating the next exploration drilling location on the block.

AED to Plug, Abandon Lempuyang Well

AED to Plug, Abandon Lempuyang Well

Thursday, April 07, 2011

AED Oil Ltd.

AED advised that the Lempuyang-1 well testing operations are now complete. Continued mechanical issues resulted in the testing program being curtailed, due to safety concerns associated with unintended gas flowing into the well from perforations and/or damaged casing. This is believed to be due to failure of the packer in the well and/or damage to the well casing above the packer. As a result, the Lempuyang-1 well will now be plugged and abandoned.

The Lempuyang-1 well intersected excellent quality reservoir sands, with gas being flowed to surface from two test intervals. Some thin gas sands were interpreted at the lower reservoir test interval (3077-3131.5 mMD – of which 24 meters were perforated). The upper
reservoir test interval (2849-2867.5 mMD – of which all 18 meters were perforated) flowed gas to surface before AED was forced to cease testing due to a down hole mechanical failure and as a result no gas flow rates could be established. The gas analysis from the
upper reservoir test shows higher levels of C1-C8s and lower CO2 compared to the lower reservoir gas sample (<0.5 mole% compared to approx. 5 mole%).

While the testing results are inconclusive, AED notes that the data obtained supports the Joint Venture's optimism in relation to the Lempuyang prospect and surrounding acreage. AED has obtained valuable information regarding the onshore geology of Brunei, within an overpressured environment. As such, the Lempuyang-1 drilling and testing results will be integrated and used for future exploration assessment of the updip area within the eastern part of Block L, where 3D seismic is currently being considered. Further appraisal and
exploration well locations will be identified for drilling in late 2011.

Further to the Company's release of April 1, 2011, the Joint Venture currently anticipates that the following exploration activity will occur at Block L in the near term:

• Seismic acquisition at West Jerudong. The Joint Venture plans to begin shooting 130km2 3D seismic over the Jerudong oil field in Q3 2011. This field was previously produced and was shut-in while still on production without being fully depleted. While the field was originally drilled on surface oil seeps and limited 2D seismic coverage; the Joint Venture intends to acquire 3D seismic to accurately map the known fault blocks and to identify additional potential oil prospects (having regard to current oil prices).
• A 3D seismic patch (13km2) and 2D seismic line (13km) east of the Lempuyang-1 well will be acquired to confirm potential structural rollover. Depending on results, an extension to the 3D seismic program of up to 150km2 could be undertaken.

The Block L Joint Venture comprises AED South East Asia Limited (50% operating interest), Kulczyk Oil Ventures (40%) and QAF Brunei (10%).