Judy Maksoud • Houston
Pemex is reportedly planning to invest $1.18 billion in natural gas projects in the Gulf of Mexico. The money will go, in part, toward bringing four new discoveries in the Veracruz basin onstream. Much of this sum will be invested in pipeline installation.
Global Industries Ltd. subsidiary Global Offshore Mexico S. de R.L. de C.V. will be getting some of the money. The company received a letter of intent from Pemex Exploration & Production to install 53 km of 36-in. diameter pipeline in the Bay of Campeche's Cantarell field.
Pemex has also contracted Global to install 29 km of 24-in. pipeline from Enlace to Uech A, also in the Bay of Campeche. The project includes installing the 29-km 24-in. pipeline, three risers, three expansion loops, and the subsea tie-in.
According to Global, these two projects represent only 7% of the 600 km of pipelines Pemex has scheduled for bid or construction in 2004 and 2005.
Houston's Signa Engineering Corp. has completed a technical study of Lukoil's Kravtsovskoye D6 project in the Baltic Sea and will continue in the role of technical advisor.
Lukoil-Kaliningradmorneft retained Signa at the end of 2003 to perform a due diligence study on a multi-well drilling operation in the Kravtsovskoye field, the largest field off the Russian enclave of Kaliningrad.
The purpose of the study was to determine computational accuracy and conceptual feasibility of 21 directional wells planned to be drilled from the D6 platform. Signa's job was to determine if the well paths would intersect and how to avoid wellbore collisions while drilling.
According to Bob Davis, Signa's president, "The report was so well received, Signa Engineering will continue to provide engineering support to Lukoil for the continued development of the Kravtsovskoye D6 project."
Lukoil began developing the Kravtsovskoye oil field more than 20 years ago to extract oil on the Baltic Sea Shelf near the Courland Spit (Kurshskaya Kosa), 13.5 mi from the shore of the Kaliningrad Region, and 3 mi from the Russian-Lithuanian border.
A Russian newspaper recently reported that Lukoil-Kaliningrad-morneft will launch a satellite that will monitor the D6 field starting in the first half of 2004.
Lukoil-Kaliningradmorneft holds the exclusive license to develop the D-6 field, which was opened in 1983. Production is expected to begin this year. Preliminary estimates place the output at 13,900 b/d.
Australia's North West Shelf Venture began gas flow into one of the world's biggest offshore pipelines in mid 1Q 2004. Woodside, operator of the venture, commissioned the line as part of LNG expansion at Karratha in Western Australia.
The $601-million, 42-in. diameter trunkline, the second major line to feed gas into the Karratha plant, was to undergo a proving period before gas was cooled into LNG at the onshore gas plant.
The trunkline complements the original 40-in. line that has been operating since 1984, linking the venture's three offshore gas production facilities to onshore gas processing facilities on the Burrup Peninsula.
The trunkline is the biggest installed in Australia and one of the biggest in the world and more than doubles the venture's offshore production capacity to transport gas from its offshore production platforms to its onshore processing facilities from 1,650 MMcf/d to 3,850 MMcf/d.
Construction of the trunkline began in 2002 and is part of the expansion of the Venture's onshore gas processing facilities. The expansion also includes a fourth LNG processing train and associated infrastructure, which are scheduled for completion by mid-year. The trunkline will have a capacity of 4.2 million metric tons per annum (mtpa) and will increase the venture's LNG production capability to nearly 12 million mtpa.
The six equal participants in the Venture are: Woodside Energy Ltd., BHP Billiton Petroleum (North West Shelf) Pty Ltd., BP Developments Australia Pty Ltd., Chevron Australia Pty Ltd., Japan Australia LNG (MIMI) Pty Ltd., and Shell Development (Australia) Proprietary Ltd.
BG India and partners Oil and Natural Gas Corp. and Reliance Industries Ltd. will invest $140 million in the Panna oil and gas field, 95 km northwest of Mumbai in 45 to 70 m of water, to target new reserves and expand current production.
The development plan includes construction and installation of two new wellhead platforms and associated infield pipelines to connect to the existing processing and compression platform. The drilling schedule will begin in 2Q 2005 and includes six horizontal wells from one platform and five horizontal wells from the other.
Implementation of the expansion program is expected to result in gross incremental recovery of 18 MMbbl and 74 bcf of gas. First production is expected in 3Q 2005.
"BG India and partners are proceeding with investment plans to target undeveloped areas of the Panna field," Nigel Shaw, CEO, BG India, said. "By applying advanced drilling techniques to extract oil and gas from the field's complex reservoir and, with gas rate management, the consortium will be able to access and develop economic reserves to realize the full potential of the field."
The two new platforms are being designed to allow future infill drilling to maximize the field's full potential. Contract awards for the new facilities will be made in April.
Exxon Mobil Corp. subsidiary Esso Exploration Angola (Block 15) Ltd. (Esso) and Sociedade Nacional de Petróleos de Angola (Sonangol) have made another discovery on block 15. Bavuca-1 is the seventeenth deepwater oil discovery on the block.
The well was drilled in 3,589 ft of water to a total depth of 10,613 ft and tested at a flow rate of 2,726 b/d of 17-18° API gravity crude.
Esso operates block 15 with 40% interest. Partners are BP Exploration (Angola) Ltd. with 26.67%, ENI Angola Exploration BV with 20%, and Statoil Angola with 13.33%. Sonangol is the concessionaire.
BP awarded contracts for FPSO hull and topsides fabrication and engineering, procurement, construction, and management for the Plutonio development offshore Angola on Feb. 10, 2004.
About a week later, the company awarded Stolt Offshore SA and Technip a contract for engineering, procurement, fabrication, and installation of umbilicals, risers, and flow lines.
The contract, worth $730 million in total, has been awarded to a consortium of Stolt Offshore and Technip.
The contract calls for installation of over 75 km of 12-in. diameter insulated production, gas injection, and service flowlines as well as 103 km of umbilicals. The consortium will also install the 12 FPSO mooring lines and 10 production manifolds to tie in the subsea wells and will perform the final hook-up of the FPSO by means of a single riser tower. The water depth at Greater Plutonio is 1,350 m.
Engineering work was initiated upon award. Installation is to be completed in 2007.
Shell Egypt made two ultra-deepwater hydrocarbon discoveries in a three-well campaign in the North East Mediterranean Deepwater Concession in the Nile Delta. The wells, drilled in over 2,400 m of water, set new water depth records for Egypt and the Mediterranean. Stena Drilling's Stena Tay semisubmersible drilled all three wells on a contract with Shell and Bapetco, a joint venture of Shell Egypt and the Egyptian General Petroleum Co.
Wells Kg45-1, Kj49-1, and La52-1 tested several hydrocarbon plays in the southwest of the concession area, yielding hydrocarbon discoveries in two locations, and providing data for an extensive evaluation program. A large volume of new data is now being integrated into geological models for the area.
Shell has found the first ultra-deep discoveries in the North West Mediterranean Deepwater Concession.
Now, the second exploration phase begins as plans move forward to commercialize the discoveries.
Shell Egypt's partners are Petronas Carigali Overseas Sdn. Bhd. and the Egyptian Natural Gas Holding Co.
Qatar Shell GTL Ltd. spudded its first appraisal well in the North field for a $5 billion, 140,000 b/d integrated gas-to-liquids project.
Two wells will be drilled in the field to determine the reservoir properties and structure and to validate the composition of the gas in the area of the North field provisionally allocated to the project.
The first well was drilled less than four months after the signing of the Qatar Petroleum/Shell Gas to Liquids heads of agreement.
The North Caspian Sea Production Sharing Consortium and KazMunaiGaz, the petroleum authority of the Republic of Kazakhstan, have approved the development plan for the Kashagan field.
With production estimates of up to 13 Bbbl of oil, the Kashagan field is one of the largest discoveries in the last 30 years. Initial production from the field is targeted at 75,000 b/d in 2008. Subsequent phases will bring production to about 1.2 MMb/d.
The consortium expects to enhance oil recovery and reduce sulfur handling by injecting raw gas back into the reservoir. This process will be accomplished by construction of facilities for onshore gas processing and offshore raw gas injection. The capital investment for full field development is estimated at $29 billion, with the first phase expected to total $10 billion.
Agip KCO will operate the field on behalf of the companies comprising the North Caspian Sea Production Sharing Consortium.
Taranaki brings new investors to New Zealand
In early February 2004, New Zealand awarded 13 of 17 exploration permits offered in the 2003 licensing round, totaling more than $87 million in new investment in the Taranaki region.
"The new exploration permits are a significant part of a broader strategy aimed at stimulating exploration and investment in oil and gas in New Zealand," Harry Duynhoven, associate minister of energy, said.
Duynhoven said he was particularly encouraged that there were a number of aggressive bids, with commitments to drill wells as early as the first year of the permit. The blocks were offered with a minimum 48-month drilling requirement. Each permit requires a minimum of one exploration well, and it is possible that more than one well will be drilled in some permits in the five-year term.
According to Duynhoven, Crown Minerals advisers are working on a range of options designed to further increase exploration activity, to address concerns over the decline of the Maui field, and to meet increasing electricity demand. His hope is that exploration will discover commercial quantities of gas to offset the rapidly depleting field.
The 13 onshore and offshore blocks brought in 23 bids, with Pogo Producing Co. of the US and Australia's ROC Oil winning New Zealand blocks for the first time. The six offshore blocks awarded were in an area extending from Cape Egmont to west of Kawhia Harbor in water depths to 200 m.
Pogo was awarded three 100%-owned licenses totaling 1,014,000 acres offshore the west coast of the North Island. Pogo's bid includes a plan to acquire at least 1,000 sq km of 3D seismic data within the first two years across the three licenses.
As planning gets underway for exploration, New Zealand Overseas Petroleum Ltd. and partners have begun a drilling program on license PEP38460, where the Tui oil find was made last year.
Diamond Offshore's Ocean Bounty began drilling the Amokura prospect, targeting Kapuni F sands 4 km from the Tui discovery. Amokura's potential is in the range 15-35 MMbbl of oil. The Amokura well is to reach its objective in mid April. After drilling Amokura, the semi will move 70 km south to drill the Pukeko prospect. The decision to drill a third well will be based on the results from Amokura and Pukeko.
New Zealand Overseas Petroleum Ltd. operates the license with 45% interest. Partners are AWE New Zealand Pty Ltd. with 20%, New Zealand Oil & Gas Ltd. with 12.5%, Mitsui E&P New Zealand Ltd. with 12.5%, and WM Petroleum Ltd. with 10%.