Tracy Dulle • Houston
US
Leed Petroleum successfully drilled the secondary target zone on its Eugene Island A-6 development well. Analysis of well logs acquired over the secondary target zone indicate a productive gas reservoir with approximately 51 ft (16 m) of true vertical pay thickness.
The well has reached a measured depth of 15,876 ft (4,839 m) and drilling continues to the third target zone. On completion of the drilling, Leed will case the remaining section of the A-6 development well and carry out production tests to determine flow rates. The refurbishment of existing facilities to accommodate production from the well is in the final stages and the company expects to begin producing shortly after well completion.
West Africa
Tullow Oil has made an oil discovery with the Odum-1 exploration well off Ghana in 955 m (3,133 ft) of water. The well, drilled to 3,387 m (11,112 ft) TD, encountered a gross oil column of 60 m (197 ft) and 22 m (72 ft) of net pay. Samples from the reservoir indicate an oil gravity of approximately 29° API.
Odum-1 will be completed and suspended as a future development well. TheSonga Saturn drillship will move to Mahogany-2, the next appraisal well on the Jubilee field.
Meanwhile, due to persistent borehole instability, Tullow has decided to suspend the Ngassa-1 exploration well and re-drill it from an alternate location.
Total has begun redeveloping the Anguille field in Gabon.
Anguille is 20 km (12 m) offshore Port-Gentil in a water depth of 30 m (98 ft) in the Grand Anguille Marine concession. Discovered in 1962, Anguille came onstream in 1966 and produced 7,500 b/d of oil in 2007 prior to redevelopment.
Phase 1 of Total’s redevelopment of Anguille field in Gabon is under way, using existing facilities. Anguille field was discovered in 1962 and brought into production in 1966.
According to Total, the redevelopment project will improve the oil recovery factor from 13% to 23% by increasing the number of drainage points and by enhancing well productivity using hydraulic fracturing and massive waterflood.
Phase 1 of redevelopment is under way with existing facilities. A dozen wells will be drilled, and the associated surface facilities will be debottlenecked.
Running from 2009 to 2011, Phase 2 entails installing new offshore infrastructure and decommissioning obsolete process units, building an onshore plant (power generation, fluid treatment, gas compression) and drilling an additional 30 wells.
The project will eliminate gas flaring on the field by 2011, as well as coastal discharges of production water.
Production is expected to increase from 2008, peaking at over 30,000 b/d in 2013-2014. The development cost is an estimated $2 billion for additional proved and probable reserves of around 150 MMbbl.
North Sea/Europe
Petrofac Energy Development has awarded Technip a $55-million contract for development of Don West and Don South West oil fields in the North Sea. The fields will be tied back to theNorthern Producer floating production facility.
Technip in Aberdeen will execute the contract, which covers project management, assembly, and installation of production, gas lift, water injection, and oil export pipelines. Technip also will install a subsea structure, eight flexible risers, two umbilicals, and complete pre-commissioning, tie-ins, and testing.
Offshore installation is scheduled for 3Q 2008 using theApache and Wellservicer vessels. The pipelines will be welded at Technip’s spoolbase in Evanton, Scotland.
TheBredford Dolphin has spudded exploration well 16/1-9 on the Draupne prospect in license PL001B offshore Norway. Planned TD is 2,275 m (7,464 ft). Results are expected in late April.
NOIL Energy operates Draupne with a 35% interest, StatoilHydro has 50%, and PA Resources holds the remaining 15%.
Ithaca Energy (UK) is drilling the third Athena oil well.
On March 10,Byford Dolphin spudded a well on Ithaca’s 70%-owned block 14/18b to test a potential southern extension of the Athena oil pool. A deviated well will be drilled to 9,000 ft (3,743 m) TVDSS to test significant potential identified in 3D seismic reprocessing.
The well will take approximately 30 days to reach the targeted Lower Cretaceous Leek sands, which constitute the Athena field. If successful, the well will be tested and suspended for future production.
Middle East
Niko Resources Ltd. has signed four offshore production sharing agreements (PSAs) with the president of the Islamic Republic of Pakistan and Government Holdings (PVT) Ltd., through the Secretariat of the Ministry of Petroleum and Natural Resources.
The initial term of the exploration work is for five years. In each block a minimum of 200 sq km (77 sq mi) of 3D seismic is to be acquired in the first phase of the initial term. The minimum work program for each block for the entire five-year initial term is 820 work units.
Work will begin immediately to establish an operating presence and organize the seismic survey work within the first year of the contract.
Niko will have a 100% participating interest in the Arabian Sea blocks near the city of Karachi and are designated as block No. 2466-7 (OFFSHORE INDUS NORTH), block No. 2466-6 (OFFSHORE INDUS Z), block No. 2465-3 (OFFSHORE INDUS X), and block No. 2465-4 (OFFSHORE INDUS Y).
The blocks are situated in the Indus Fan system, the second largest submarine fan known in the world, and cover an area of approximately 10,000 sq km (3,861 sq mi), Niko says. Water depths range from transition zones (onshore to offshore) to deepwater.
Oil and Natural Gas Corp. Ltd. (ONGC) announced an offshore discovery in well B-12-11 in PEL block BOFF 1, 2, and 3 in the Arabian Sea.
Asia
ONGC says it will take a 30% additional stake in the development phase of Gulf-A in the joint venture block of CB-OS-1, at the northern-most end of the Gulf of Cambay, bringing its share to 55.26% of capex. JV partners are Tata Petrodyne and HOEC.
Niko Resources Ltd. has discovered gas in the NEC 25 block of the Mahanadi basin, off the Orissa coast in the Bay of Bengal, India.
This block, covering 10,775 sq km (4,160 sq mi) in depths ranging between 20 and 600 m (66 and 1,968 ft), was awarded under the bidding round of NELP I. Niko holds a 10% interest in the block.
This is the eighth discovery in the block. Development plans have been submitted to the Directorate General of Hydrocarbons for approval.
Well NEC 25-J1 was drilled on the southern portion of the area covered by the 2007 3D seismic survey aimed at exploring upper Miocene slope sands in the deeper part of the block. This well was drilled at a water depth of 478 m (1,568 ft) to the target depth of 2,926 m (9,600 ft). For the first time in this basin, the well encountered high quality, multi-darcy gas-bearing reservoir sands in the interval 2,484-2,495.5 m (8,150-8,187 ft).
J1 is part of an ongoing exploration program in NEC 25. Two rigs are drilling exploration wells B3 and A9A. Upon completion of these wells, additional prospects are scheduled to be drilled. Well results are being integrated into the evaluation of NEC 25 and future drilling locations are being assessed.
Australia
MEO Australia Ltd. has made a discovery with Blackwood-1 off Australia’s northwest coast.
Seadrill’s jackupWest Atlas has completed a series of logging runs, including the recovery of hydrocarbons to surface by modular dynamics testing (MDT) downhole sampling. Additionally, a number of core samples through the column have been obtained.
The gas, core samples, and log data are being analyzed by petrophysical contractors. Initial gas analysis conducted on the rig has confirmed that the gas is relatively dry and contains CO2 levels in the 25% to 30% range (very similar to Evans Shoal gas), which is suitable for methanol production, according to MEO.
Given the recovery of hydrocarbons to surface and strong electric log evidence of a hydrocarbon column in the Plover sandstone formation of the Blackwood structure, formal declaration of a discovery pursuant to clause 34 of the Petroleum (Submerged Lands) Act 1967 has been made to the Designated Authority.
The MEO-operated Blackwood-1 well has been plugged and abandoned as planned. The discovery well is 100% funded as a sole risk by MEO.
Roc Oil (WA) Pty Ltd. has drilled the Frankland-2 appraisal well at WA-286-P, Perth basin, offshore Western Australia, to TD of 2,330 m (7,644 ft) below the rotary table from theWilCraft jackup drilling rig.
The well intersected gas in the target sands, confirming hydrocarbons in the eastern region of the Frankland field. The reservoir is of poorer quality than that encountered in Frankland-1. The Frankland-2 well is being P&A’d.
ROC and the joint venture will evaluate data from the well, and in conjunction with the results of the 3D seismic survey currently being processed, the field will be re-evaluated for possible further appraisal.
Frankland-2 is approximately 1 km (0.6 mi) northeast of the 2007 Frankland-1 well gas discovery.
Following the drilling of Frankland-2, ROC and the joint venture plan to drill the Dunsborough-2 to appraise the 2007 Dunsborough oil discovery.
Participating Interests in the WA-286-P joint venture are Roc Oil, operator with 37.5%; AWE Oil (Western Australia) Pty Ltd. with 27.5%, ARC Energy (Offshore PB) Ltd with 30%, and CIECO Exploration and Production (Australia) Pty Ltd. with 5%.
Hydrocarbon reserves in Nexus Energy Ltd.’s Crux field in the Browse basin have increased following the successful drilling of the Crux-3 and Crux-4 appraisal wells off the northwest coast of Western Australia.:
• The Proved plus Probable plus Possible estimate (P10) has increased from 78.3 MMbbl to 83.1 MMbbl, an increase of 6.1%.
• The Proved plus Probable estimate (P50) has increased by 12.5% from 66.3 MMbbl to 74.6 MMbbl.
• The Proved reserves estimate (P90) has increased from 54.9 MMbbl of condensate to 67.0 MMbbl, an increase of 22%.
