Beach flows high condensate in Cooper basin

July 19, 2010
Beach Energy Ltd., Adelaide, has tested an unexpectedly high condensate flow in its Canunda-1 wet gas discovery in the PEL 106B permit in the western Cooper basin of South Australia.

Beach Energy Ltd., Adelaide, has tested an unexpectedly high condensate flow in its Canunda-1 wet gas discovery in the PEL 106B permit in the western Cooper basin of South Australia.

The company says the initial gas flow rate of 10.5 MMcfd was accompanied by a condensate to gas ratio of 180 bbl/MMcf. This forced the operator to choke back the flow rate due to limits on liquid storage and available trucking from the field.

The well produced more than 2,500 bbl of condensate during the 10-day test period.

Testing and analysis will continue during the next few weeks before a condensate reserve figure is determined. The producing formation is the upper of three Permian Patchawarra formation sands.

In May this year the company's Brownlow-1 discovery in the same permit flowed gas at 18.1 MMcfd with 100 bbl of condensate for every 1 MMcf of gas.

Beach has operatorship and equal stake in the permit with Drillsearch Energy Ltd., Sydney.


Tap Oil Ltd., Perth, plans to spud the Mawar-1 wildcat on an oil prospect on the Belait anticline in Block M in southwestern Brunei around July 19, 2010.

Mawar-1, first well to be drilled in Block M since 1988, is to be followed by Markisa-1. A Tap Oil-led joint venture will drill the wells on behalf of Brunei National Petroleum Co.

The Mawar-1 location is 30 km south of giant Seria oil field. The directional well is to test multiple sandstone objectives in Mid-Late Miocene Belait at 1,300 m in a fault compartment on the anticline.

Block M covers 3,011 sq km in the Baram Delta. Block participants are Tap Energy (Borneo) Pty. Ltd. operator with 39%, Kulczyk Oil Ventures Inc. 36%, China Sino Oil Co. Ltd. 21%, and Jana Corp. Sdn. Bhd. 4%.


Melrose Resources PLC, Edinburgh, has spudded the Kavarna East-1 exploratory well using the Jupiter jack-up on the Galata block in the Black Sea off Bulgaria to test a low-risk prospect between Kavarna and Kaliakra gas fields.

Kavarna East has a gross recoverable resource estimated at 12 bcf with 80% chance of success. A discovery would be developed via the Kavarna field flow line.

After drilling the well, the jack-up will be used to install the subsea tree for the Kaliakra field development well. Later it may be used to drill a well on the Kaliakra East prospect, 59 bcf resource with 34% chance of success. Drilling is contingent on confirmation that the seabed conditions will allow the jack-up to operate in the required water depth.

The Bigfoot pipelay barge is expected to arrive at the Galata block in early August to install the flow lines for the Kavarna and Kaliakra gas field developments.


Colombia awarded Alange Energy Corp., Toronto, three more exploratory blocks that total 217,418 ha in the Magdalena basin.

The VNM 35 block covers 7,704 ha in Middle Magdalena near Nare and Las Quinchas oil fields. The block's main reservoirs are Tertiary sandstones sourced by the La Luna formation in potential structures with oil higher than 15° gravity. The 36-month first exploration phase calls for seismic and one exploratory well.

The VSM 12 block covers 56,730 ha near San Francisco, largest oil field in Upper Magdalena. The block's main reservoirs are Caballos sandstones sourced by the Villeta formation, with 25° gravity oil or lighter. The 36-month initial phase calls for seismic and drilling one exploratory well.

The VSM 13 block, also in Upper Magdalena near Tello, Rio Ceibas, Pijao, Dina, and Tenay oil fields, covers 58,693 ha. It has potential for oil of 25° gravity or lighter in Caballos and Monserrat sandstones sourced by Villeta. The first 36-month period requires seismic and drilling one exploratory well.

Alange Energy in June was awarded the LLA 41 and COR 33 blocks in the Llanos and Cordillera basins, respectively.


Cairn Energy PLC last week spudded the Alpha-1 exploratory well on the Sigguk block 175 km off Disko Island in the Davis Strait off western Greenland.

The drilling program targets the Alpha and T8 prospects in 300-500 m of water. The wells have planned depths of 4,200 m and 3,250 m. Drilling times are estimated at 55 and 38 days, respectively (see map, OGJ, Aug. 24, 2009, p. 38).

Each is being drilled using a pilot hole through the initial top hole section.


San Leon Energy PLC, Dublin, let a contract to PGS Ventures AS for a 300 sq km seismic survey in the Slyne basin on the Atlantic margin west of Ireland.

The survey on Exploration License 4/06 is to be complete by the end of August. San Leon acquired a 50% interest in the license when it bought Island Oil & Gas in May 2010. Lundin Petroleum AB, Stockholm, has the other 50%.

John Buggenhagen, San Leon vice-president of exploration, considers the Atlantic margin to have the potential that the North Sea had 40 years ago.


Petroleos Mexicanos SA let a contract to Electromagnetic Geoservices ASA for 3D electromagnetic surveys in Mexican waters of the Gulf of Mexico.

The multiyear deal, worth at least $150 million, calls for 30 deepwater 3D EM surveys. Pemex and EMGS did not specify the areas to be surveyed starting in late August 2010.


Mitra Energy Ltd. and Petrovietnam Exploration Production Corp. have signed a production sharing contract with Petrovietnam for Block 46/07 off Vietnam in the northeastern Malay-Tho Chu basin.

The block covers 3,281 sq km adjacent to Mitra-operated Block 51 and in which PVEP also has a direct interest. The two blocks have clear operational synergies, Mitra Energy said.

Interests in Block 46/07 are Mitra 70% and operator and PVEP 30% equity. The initial 3-year PSC work program consists of shooting and processing of 300 sq km of 3D seismic surveys and drilling two exploration wells.


GeoResources Inc., Houston, plans one reentry and three new wells to begin drilling in late July or early August in St. Martinville field, St. Martin Parish, La.

A high-resolution 3D seismic program has been shot and processed and is being integrated with subsurface control and being interpreted. The last well, Standard of Kansas-7, has proved reserves estimated at 250,000 bbl and cost $1 million to drill and complete.

The salt dome has produced more than 15 million bbl of oil and 16 bcf of gas from less than 7,000 ft. The deeper Discorbis has yielded 124 bcf and almost 2 million bbl of oil at 10,000 ft. GeoResources has 97% working interest and 91% average net revenue interest in the field.

Mannon L. Walters, Evansville, Ind., completed the Darsey et al. No. 1 reentry well in 63-20s-18e, Lapeyrouse field, Terrebonne Parish, La., for 98 b/d of oil and 80 Mcfd of gas.

The flow is on an 11⁄64-in. choke with 600 psi flowing tubing pressure from perforations at 8,010-12 ft measured depth.

The well was drilled directionally to develop attic oil reserves and to test additional deeper and shallower sands on the upthrown side of a major fault. The geology was based on both production history and 3D seismic.

The well identified 11 pay zones, at least 3 of which had never been produced in Lapeyrouse field, along with other zones new to this fault block. The company plans more drilling in the field, which dates to the 1950s.

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