Blog Archives

Canada: ExxonMobil Gets Approval for Hebron Field Development

The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) has approved ExxonMobil’s Hebron Development Application.

The approval of the Development Plan now enables ExxonMobil Canada Properties Limited to proceed with development of the Hebron Field, which is estimated to contain 707 million barrels of of recoverable resources..

Hebron is a heavy oil field estimated to have 400 – 700 million barrels  The field was first discovered in 1981, and is located offshore Newfoundland and Labrador in the Jeanne d’Arc Basin 350 kilometres southeast of St. John’s, the capital of Newfoundland and Labrador. It is approximately 9 kilometres north of the Terra Nova project, 32 kilometres southeast of the Hibernia project, and 46 kilometres from the White Rose project. The water depth at Hebron is approximately 92 metres.

The Hebron field will be developed using a stand-alone concrete gravity based structure (GBS). The GBS will consist of a reinforced concrete structure designed to withstand sea ice, icebergs, and meteorological and oceanographic conditions at the offshore Hebron Project Area. The preliminary GBS concept has a single main shaft supporting the topsides, encompassing all wells.

The Hebron co-venturers are: ExxonMobil Canada Properties (36%), Chevron Canada Resources (26.7%), Suncor Energy Inc. (22.7%), Statoil Canada (9.7%) and Nalcor Energy (4.9%).

Source

Kiewit-Kvaerner JV Work on Exxon’s Hebron GBS in Canada

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Kiewit-Kvaerner Contractors joint venture, has been authorized by ExxonMobil Canada Properties (EMCP) to proceed with work on the Hebron Project gravity based structure (GBS) project offshore Newfoundland and Labrador, Canada.

The authorization comes after the substantial completion of front end engineering and design services and awards the next phase, which includes detailed engineering, procurement and construction (EPC) related services. Kvaerner estimates its share of this work to be approximately USD 125-150 million.

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Hebron is a heavy oil field estimated to have 400 – 700 million barrels of recoverable resources. The field was first discovered in 1981, and is located offshore Newfoundland and Labrador in the Jeanne d’Arc Basin 350 kilometres southeast of St. John’s, the capital of Newfoundland and Labrador. It is approximately 9 kilometres north of the Terra Nova project, 32 kilometres southeast of the Hibernia project, and 46 kilometres from the White Rose project. The water depth at Hebron is approximately 92 metres.

The Hebron field will be developed using a stand-alone concrete GBS. The GBS will consist of a reinforced concrete structure designed to withstand sea ice, icebergs, and meteorological and oceanographic conditions at the offshore Hebron Project Area. The preliminary GBS concept has a single main shaft supporting the topsides, encompassing all wells.

The Hebron co-venturers are: ExxonMobil Canada Properties (36%), Chevron Canada Resources (26.7%), Suncor Energy Inc. (22.7%), Statoil Canada (9.7%) and Nalcor Energy (4.9%).

Source

Canada: Subsea 7 Receives Terra Nova Field SURF Contract

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Subsea 7 S.A. announced the award of a SURF contract valued at approximately $100 million from Suncor Energy on the Terra Nova Field, situated 350km south east of St John’s, Newfoundland, offshore Canada.

The contract scope includes the management, engineering and installation of nine 300 metre replacement risers and associated flowlines, jumpers and tie-ins.

Engineering and project management will commence immediately at Subsea 7’s St John’s office, with offshore operations due to commence in summer 2012 utilising Subsea 7’s world-class construction and diving vessels.

Phil Simons, Subsea 7’s Vice President Canada, Mediterranean & Russia said, “As a leading seabed-to-surface engineering, offshore construction and services company we are delighted to have won this prestigious contract which builds on our expertise and strong track record and further supports the development of our St. John’s office.”

Source

Newfound Billions Of Barrels Of Shale Oil In Newfoundland

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Source: Shoal Point Energy website

by Marco G.

The advent of new “fracking” technology has brought previously ignored and non-producible oil source rocks back to the forefront of petroleum exploration. The high pressure hydraulic rock fracturing technology has allow present day oil drillers to fracture and condition the oil source shale rock in order to recover a portion of the oil-in-place. The shale oil stories such as the North Dakota Bakken or the Texas Eagle Ford are now common place for the petroleum environment. There is another shale oil story that has yet to hit the news flow and so you may not be aware of it. It may be an extension of the Utica shales but situated much more northern in Newfoundland Canada.

Shale Oil Basics

Shales with oil are considered the source rocks for conventional oil deposits that are trapped within a seal rock’s anti-cline or hump in the earth’s geology. The source rock was originally a settlement layer underwater on the Earth’s surface where eons of organic matter becomes trapped in the sediments. With geologic events, the rock is overlain with other rocks and becomes embedded deeper in the Earth’s crust. The source rock then has passes through a time frame of the Earth’s geothermal furnace where the high heat and pressure at depths transforms the organic matter into gas, oil or coal in a successive cooking process of maturation.

One clue to the shale oil prospectivity would be the “Total Organic Content” (TOC) of the shale. Another clue is the type of kerogen that the organic matter constitutes and the Vitrinite Reflectance value that indicates whether oil is present or not. A third measure of the prospect is the porosity of the rock or its ability to hold oil within its pores. Finally, there is the permeability of the rock as to whether the oil can be transported from place to place within faults and fractures. This is where the drillers assist the shale layer in releasing their crude oil by hydraulically stimulating multiple fractures along the drilling path.

Location, Location and Location

This shale oil prospect is the Green Point Shale (GPS) that is in the Port au Port Bay area on the west coast of Newfoundland, the island just off Labrador on Canada’s mainland. Here is a link to a good map about Oil and Gas activities around Newfoundland. The specific drilling presently is on well 3K-39, in the map following:

As in real estate, the three most important factors to consider for a resource company are the three location factors. Firstly is the location in a safe jurisdiction, not prone to government seizure? Yes, this property is in democratic Canada on the Atlantic seaboard, about one thousand miles north-east of New York. Secondly, is this property in an environmentally supportive governing jurisdiction? Yes, this exploration property is in oil and environmentally friendly Newfoundland, where there is an oil drilling history and a refinery at Come-by-Chance, Newfoundland. Thirdly, is there the infrastructure to bring in supplies and to take the products to markets? Yes, there are roads and power and ports such as Corner Brook and Stephenville, within the vicinity.

Newfoundland Oil Drilling History

Off the east coast of Newfoundland, there has a long history of oil development including the Hibernia, Terra Nova and White Rose fields discovered 200 mile offshore in the 400 feet deep Jeanne d’arc Basin in the Grand Banks area in 1970s and 80s. These projects are now owned by a consortium of big oil partners including Suncor Energy (SU), Exxon Mobil (XOM), Statoil (STO), Husky Energy (HUSKF.PK) , Murphy Oil (MUR) and Chevron (CVX). These fields are producing 300,000 barrels of light crude per day.

On the west coast of Newfoundland there has been minor oil exploration and production since the late 1800s. Offshore, is the Anticosti Basin, which was explored with seismic in the 1990s by Hunt, PanCanadian, Talisman (TLM), BHP and Exxon Mobil (XOM) . Onshore in 1994, Hunt Oil drilled the Port au Port #1 well and hit 51 API oil flowing in two intervals flowing at 1528 and 1742 bopd over nine days, but this diminished with time. The hypothesis was that this was a porous zone within a larger trend.

Currently Shoal Point Energy is extending the 3K-39 well and is about to perform open hole tests on the extension.

Billion Barrels of Oil-In-Place

The fascinating geology of the Green Point Shale is that it is considered an “Allochthon”, that is the landform has been moved here by geologic events, they were not formed in-situ. The hypothesis is that the geologic forces that moved the shale layer here also crumpled up the shales in a folding thickening pattern similar to an accordion. The layers are “tectonically thickened by imbrication (stacking)”, so that the shale layer that should be only tens of metres thick naturally ends up being a few hundred meters thick.

The Newfoundland government documents offering the oil exploration licenses for bids says this about the specific area:

Port au Port #1 oil and gas tests and the presence of oil in seeps and drilled wells demonstrate that source rocks are mature and that oil and gas was generated and migrated into traps. After trap formation there were direct migration routes through porous beds or faults from the Green Point shale into allochthonous reservoirs.

With source rocks in the oil window or dry gas window, trap preservation and presence of adequate reservoir remains the main risk factors in the Paleozoic basins.

This tells me that the shale rocks are oil bearing and the risk is how to find the reservoir. Even if conventional oil pools are not located, these thick shale beds can be now produced with modern “fracking” technology.

With the crumpled and thick layers of shale, this gives cause to the lucrative aspects of this story. The thicken layer implies an increase in the amount of oil source rocks available for extraction. The geologic forces may have also assisted in the stressing of the shales to make them permeable with large faults and micro-fracturing. The testing performed by NuTech of Texas on the geology gives some very interesting results as shown following:

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Source: Shoal Point Energy website.

The GPS shale oil layers are uncommonly thick and thus gives a multiple to the amount of possible oil-in-place. Note the number for Long Point well M16 gives 930 MMBO per section, almost a billion barrels of oil-in-place.

Recent Alliance Events

The drilling for 3K-39 is operated by Shoal Point Energy (SHPNF.PK) of Toronto. On October 26, 2011, SPE announced an agreement to acquire 100% of EL 1070 from Canadian Imperial Venture (CIMVF.PK) and also increased their interest in EL 1120 to 80% from Ptarmigan Energy. This agreement acquires the whole of EL 1070 and acquires further interest in EL 1120 which abuts.

On January 17th, SPE announced an agreement with NWest Energy (NWNYF ) to acquire Exploration License (EL) 1079R which is contiguous to EL 1120 and the EL 1070 where the 3K-39 well is. This agreement acquires EL 1079R which increases the holdings three times to basically the whole of the GPS area in Newfoundland. It seems SPE is positioning for a successful well test of 3K-39.

The Catalyst for Discovery

The drilling of 3K-39 is for the appraisal purposes of the GPS. The latest update from SPE on February 22, 2012 was:

Shoal Point is pleased to announce that operations at the DLMC Shoal Point 3K-39z well are continuing, and that the side-tracked well is expected to reach a measured depth of approximately 1,800 metres over the next few days, after which the borehole will be logged, and a open hole test will be run over the entire approximately 190 metre open hole section below the whipstock. Thereafter, the hole will be drilled to final total depth.

As announced previously, the current work will also involve up to four tests out of the casing in the existing 3K-39 borehole, subject to final regulatory approvals of the testing program. All tests will occur within the Green Point Formation, and will test the flow potential and reservoir characteristics of unstimulated, fractured Green Point shales. The balance of the program is expected to take up to 45 days to complete.

SPE states that this GPS prospect has the potential for both conventional oil (due to the fractured formation) as well as unconventional shale oil. This well will test for the flow potential in addition to the prospectivity and the potential resource size for the total Green Point Shales. The numbers for the oil-in-place is estimated to be very large.

Shoal Point Energy’s US symbol is SHPNF and may be traded here. The author holds Shoal Point Energy shares.

References:

Feb 14, 2012

Shoal Point Executive Summary

Jan 26, 2012

George Langdon’s presentation to the Shoal Point Energy Annual General Meeting

Dec 14, 2011

George Langdon Presentation to the World Frontier Exploration Congress in London, England

Nov 2011 – Resource World Magazine Feature Story on Shoal Point Energy

Equities mentioned – XOM, CVS, SU, TLM, STO, HUKSF, MUR, SPHNF, NWNYF, CIMVF

Disclaimer: The information and opinions contained within this document reflect the personal views of the author and should be viewed as food for thought and amusement only. The author may from time to time have a position in any of the securities mentioned. There are no guarantees of the accuracy, reliability or completeness of the information contained herein. Independent due diligence and discussions with one’s own investment and business advisor is strongly recommended. These writings are not to be construed as an offer or solicitation with respect to the purchase or sale of any security or as an endorsement of any product or service. We do not request or receive compensation in any form in order to feature companies in this publication. It is prohibited to copy or redistribute this document to any type of third party without the express permission of the author. This document may be quoted, in context, provided proper credit is given.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

Additional disclosure: The author holds Shoal Point Energy shares.

Worldwide: Field Development Project News

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Dec 9 – Dec 15, 2011

This week the SubseaIQ team added 0 new projects and updated 22 projects. You can see all the updates made over any time period via the Project Update History search. The latest offshore field develoment news and activities are listed below for your convenience.

Africa – Other
Anadarko Spuds Lagosta-2 in Rovuma Area 1
Dec 13, 2011 – Anadarko is currently appraising its Lagosta-2 well with plans to complete it towards late January 2012. The well is located Offshore Area 1 of Mozambique???s Rovuma Basin. The discovery well encountered more than 550 net feet (168 net meters) of natural gas pay in multiple high-quality Oligocene and Eocene sands. The consortium is currently in early-stage discussions with major LNG off-takers in the Asian and European markets to secure long-term commercial contracts for the planned production from the Rovuma Area 1 project. Anadarko operates the area with a 36.5% working interest. Co-owners in the area include Mitsui E&P Mozambique Area 1, Limited (20%), BPRL Ventures Mozambique B.V. (10%), Videocon Mozambique Rovuma Offshore, Ltd. (8.5%).
Project Details: Lagosta
Africa – West
SBM Offshore, Eni Finalize Xikomba FPSO Lease and Operate Contract
Dec 14, 2011 – Eni and SBM Offshore have executed contracts for the 12-year charter and operation of Xikomba FPSO for Block 15/06. The development plan calls for the relocation of the existing Xikomba FPSO, which has been operated under contract for ExxonMobil since 2003. The vessel will undergo a major upgrade in order to meet new project specific requirements. First production from the FPSO is targeted for 2014.
Project Details: Kizomba, Block 15
N. America – Canadian Atlantic
Husky Conducts Testing on West White Rose
Dec 12, 2011 – Suncor Energy, a partner in the White Rose project, stated that operations are proceeding on the field with a pilot project to provide additional information about the West White Rose field that is part of the White Rose Extension. The operator completed two pilot wells in 3Q 2011, with water injection support expected to come on-stream late in 2011. The subsea development will connect to the SeaRose FPSO, which has a storage capacity of 940,000 barrels of oil. The White Rose field is located about 217 miles (349 kilometers) east of St. John, Newfoundland.
Project Details: White Rose
N. America – US GOM
Anadarko Sanctions Lucius Development in GOM
Dec 15, 2011 – Anadarko has given the green light for the development of the deepwater Lucius development in the GOM. The development plan calls for six producing wells connecting to a truss spar with a production capacity of 80,000 bopd and 450 MMcf/d. The spar is currently being constructed at Technip’s facility in Pori, Finland. Drilling will begin in 2012 with first production slated for 2014.
Project Details: Lucius
Subsea 7 Scores Two GOM Contracts
Dec 12, 2011 – Subsea 7 received two engineering and installation contracts from Shell for the Cardamom and West Boreas projects in the GOM. The company’s scope of work on West Boreas is the installation of a 20,000 feet (6,096 meter) long umbilical, as well as subsea distribution hardware for the field. Installation will occur in water depths of up to 3,146 feet (959 meters) in the Mississippi Canyon block area. For the Cardamom project, the company will install a 30,400 feet (9,266 meters) long umbilical plus subsea distribution hardware for the field in water depths up to 2,999 feet (914 meters) in the Garden Banks block area. Subsea 7 will use the Skandi Neptue construction vessel for both projects. Both oil fields are slated to commence production in 2013.
Project Details: Auger
ATP Succesfully Tests Clipper Well
Dec 12, 2011 – ATP has successfully completed and tested the second Clipper well on the field in the deepwater GOM, which flowed at rates of 9,000 Bbls per day and 4.6 MMcf/d. This well, combined with the first Clipper well, brings the total test rates to about 13.7 MBbls of oil per day and 50.2 MMcf/d of natural gas or 22 MBbls equivalent per day. The well logged about 56 feet (17 meters) of net oil pay, confirming reserves previously booked. ATP has hired a pipeline lay barge for the Clipper wells until 3Q 12, and will tie-in both the GC 300 No. 4 and No. 2 wells to the Murphy Oil-operated Front Runner production facility. Clipper No. 4 is located at Green Canyon Block 300, and resides in 3,450 feet (1,052 meters) of water. ATP operates Green Canyon block 300 with a 55 percent working interest.
Project Details: Clipper
Noble to Appraise Gunflint
Dec 12, 2011 – Appraisal operations should commence on the Gunflint discovery in the near future. The operator plans to use the ENSCO 8501 (UDW drillship) to appraise the find to help determine the resource range of the discovery before final development planning and sanctioning of the field occurs. A discovery was made on Gunflint in October 2008. Noble Energy operates the oil discovery, which is located on Mississippi Canyon Block 948 in the GOM.
Project Details: Gunflint (Freedom)
S. America – Other & Carib.
Kosmos Enters Suriname Acreage
Dec 14, 2011 – Kosmos Energy has signed two Production Sharing Contracts with Staatsolie Maatschappij Suriname N.V., the national oil company of Suriname, for Blocks 42 and 45 offshore Suriname. The two blocks span nearly three million gross acres, in water depths of between 650 and 8,500 feet (198 and 2,591 meters). Block 42 covers 1.5 million acres and Block 45 extends 1.3 million acres. Drilling has not occurred in either block. In the initial exploration phase under each of the contracts, Kosmos plans to acquire 3D seismic data. First drilling is targeted for 2014. Kosmos will wholly own and operate both blocks, making it the first acreage acquired by the company outside of West Africa.??
CGX Energy Preparing to Drill Eagle-1 in 2012
Dec 13, 2011 – CGX Energy plans to spud its Eagle-1 prospect in the Corentyne Petroleum License in 1Q12. The well has a proposed depth of 14,000 feet (4,267 meters) and will be drilled by the Ocean Saratoga (mid-water semisub).
Rockhopper Hits Again in Falkland Basin
Dec 13, 2011 – Rockhopper Exploration has made its third discovery in the north Falkland Basin. The 14/15-4 well penetrated multiple reservoir targets: Beverley, Casper South, Casper and Sea Lion Main Complex. A recently performed wireline logging and formation test have indicated that all four targets are hydrocarbon-bearing, and no water wet sands were observed in the well. The well also encountered hydrocarbons in the Beverley and Casper South reservoirs. The well penetrated the Beverley prospect near the crest of the structure. The gross reservoir package of 89 feet (27 meters) was approxiametly 33 feet (10 meters) thicker than prognosed, while net gas pay was 85 feet (25.8 meters). However, an analysis of mud logs indicates the gas is likely to be a wet gas. Rockhopper believes that the gas/oil contact observed in Casper at well 14/10-9 and Casper South at well 14/15-4 is likely to exist in Beverley. As a result, the company believes Beverley may be oil-bearing downdip. Furthermore, it was discovered that Casper South has a separate fan lobe, to the south of and apparently in communication with the Casper fan, which the company mapped to extend over an area of greater than 100 square kilometers with significant down-dip oil potential. The well also penetrated the Sea Lion Main Complex, about 7.5 miles (12.1 kilometers) from the 14/10-2 discovery well, 4 miles (6.3 kilometers) to the south of well 14/10-9 and 8.5 miles (13.8 kilometers) from the northern most successful appraisal well 14/10-7. Rockhopper believes the well is close to the southernmost limit of the Sea Lion field and at the outer edge of its former maximum case area. Rockhopper will now complete a short offset sidetrack to obtain core in the Beverley, Casper South and Sea Lion Main Complex formations.??The company earned a 60 percent interest through the drilling of the well, which was previously controlled by Desire Petroleum.
Project Details: Sea Lion
Repsol Commences Exploratory Drilling Offshore Guyana
Dec 12, 2011 – Repsol has spud the Jaguar prospect offshore Guyana using the Atwood Beacon (400 feet ILC). The high-pressure, high-temperature well is located in the Georgetown Block near the border with Suriname. The well has a proposed total depth of 21,325 feet (6,500 meters) with drilling operations expected to last six months. Partners in the Georgetown Block are Repsol (operator, 15 percent); YPF (30 percent); Tullow Oil (30 percent); CGX (25 percent).
Australia
Chevron Hits Gas Pay in Vos-1
Dec 15, 2011 – Chevron has made a natural gas discovery in the Exmouth Plateau area of the Carnavon Basin, offshore Western Australia. The Vos-1 well encountered about 453 feet (138 meters) of net gas pay. Chevron stated that this is the 12th offshore discovery made in Australia since mid-2009. Vos-1 reached a depth of 12,461 feet (3,798 meters) in a water depth of 4,869 feet (1,484 meters). Chevron operates the WA-439-P permit with a 50 percent interest with Shell holding the remaining interest.
Apache Plugs, Abandons Hannah-1
Dec 13, 2011 – Apache plugged and abandoned its Hannah-1 well after the well came up dry. The primary target was intersected at 3,937 feet (1,200 meters), but significant hydrocarbons were not present in the reservoir. The well reached total depth at 4,488 feet (1,368 meters). The well is located in permit TP/8, about 11 miles (18 kilometers) east of Barrow Island. TP/8 joint ventures consist of Apache (operator, 68.50 percent), Kufpec (19.27 percent) and Tap (12.22 percent).
Project Details: Hannah
Europe – North Sea
BP Delays Skarv Production Date
Dec 15, 2011 – PGNiG, a partner in the Skarv development, says that production from the field will defer from the first quarter 2012 to the second quarter 2012. The consortium has rescheduled the installation work, and says that this will significantly reduce the need of the planned stoppages in production in 2012. Natural gas production for 2012 was revised and forecasted at .211Bcm, instead of the previously reported .240 Bcm. Production of crude oil (including Natural Gas Liquids) in 2012 is estimated at 180 thousand tonnes, instead of the previously reported 250 thousand tones. Located in the northern part of the Norwegian Sea, the Skarv/Idun unit consists of two separate fields, situated in water depths of 1,148 to 1,476 feet (350 to 450 meters). The unitized equity of the project, which BP serves as the operator, is BP (24 percent), Statoil (36 percent), E.On Ruhrgas Norge AS (28 percent), and PGNiG Norway AS (12 percent).
Project Details: Skarv/Idun
Providence Encounters Notable Gas Shows in Barryroe
Dec 14, 2011 – Providence Resources announced that well 48/24-10 has encountered notable gas shows in the PSE Seven Heads Limited operated gas reservoir, which overlies the Barryroe oil discovery. The well has reached section total depth of 4,038 feet (1,231 meters) true vertical depth subsea, with the key geological horizons encountered close to the pre-drill depth prognosis. Following casing of this section, the well will be drilled through the underlying primary and secondary Barryroe oil reservoir targets to a TD of 7,464 feet (2,275 meters) TVDSS.??The GSF Artctic III semisub is drilling the well. Barryroe is located in 328 feet (100 meters) of water about 31 miles (50 kilometers) offshore Ireland in Standard Exploration License (SEL) 1/11. Providence operates the license with a 50 percent interest.
Project Details: Barryroe
Valiant Progresses with Causeway Development
Dec 14, 2011 – Project execution for the Causeway development is progressing with all of the long-lead items now ordered with main contracts in place. First oil is anticipated to commence in the second half of 2012. Causeway is located on Blocks 211/22a and 211/23d in a water depth of 350 feet (107 meters) in the UK sector of the North Sea.
Project Details: Causeway
Petrofac Finalizes Don Work Program
Dec 14, 2011 – Petrofac and Valiant Petroleum are currently finalizing the Don Area work program for 2012. The scope of work includes a new production well on Don Southwest, a new water injection well on West Don and a sidetrack of an existing West Don production well, which is currently shut-in. Don Southwest is located on UK Block 211/18a roughly 6 miles (9.5 kilometers) away from the UK/Norway median line. The field is 60 percent owned by Petrofac, serving as operator; Valiant owns the remaining 40 percent interest.
Project Details: Don Area
Premier Plans to Commence Drilling on Bluebell
Dec 13, 2011 – Premier plans to spud the Bluebell exploration prospect by year-end. Canadian Overseas Petroleum Limited, who entered a farm-in agreement with Premier last year, said a drilling vessel has been contracted. The well has a target depth of 7,550 feet (2,300 meters) to evaluate the Paleocene anomaly. Bluebell is located on UK Blocks 15/24c and 15/25f.
Project Details: Bluebell
Suncor Proposes to Drill Romeo in 3Q12
Dec 12, 2011 – Suncor Energy plans to drill a well on the Romeo prospect, a HPHT well, in 3Q12. The Romeo prospect is considered a small, rotated Upper Jurassic fault terrace on the flank of the West Central Graben. The prospect lies in Block 30/11c, which covers an area of 11,738 acres (47.5 square kilometers) and is located in the UK sector of the North Sea. The water depth of the site is 280 feet (85 meters). Suncor Energy operates the block.
Ithaca Updates Ops on Athena Development
Dec 12, 2011 – Ithaca Energy announced that conversion operations on the Athena FPSO is still underway, however, the conversion scope has proved to be more extensive than previously thought. BW Offshore, the party responsible for the conversion, and Dubai Dry Docks have completed a fast-track engineering project to deliver the vessel close to the original schedule. Additional work is being performed to ensure that production is not delayed once the vessel is moored on the field, stated the operator. Once the vessel leaves Dubai, it will sail to the North Sea and hook-up to the pre-installed production buoy. In-field commissioning will be minimized by the comprehensive dockside commissioning being undertaken in Dubai. It is anticipated the vessel will sail from Dubai in early 2012. Furthermore, installation of subsea equipment has progressed well and remains within schedule; and all development wells are ready for production. The Athena field lies on Block 14/18b in 440 feet (134 meters) of water. Ithaca Energy serves as the operator of the field, holding a 22.5% interest; Dyas UK Ltd. holds 47.5%; EWE holds 20%; and Zeus holds the remaining 10% interest.
Project Details: Athena
ConocoPhillips Hits Gas Pay in North Sea
Dec 12, 2011 – ConocoPhillips has discovered gas in wildcat wells 7/11-12 S and 7/11-12 A on the Peking Duck field in the Norwegian sector of the North Sea, about 12 miles (19 kilometers) southwest of the Ula field. The objective of well 7/11-12 S was to prove petroleum in Triassic reservoir rocks. A 131-foot (40-meter) gross gas column was encountered in Jurassic age reservoir rocks, but the reservoir quality in Triassic rocks was poorer than expected. The objective of the sidetrack, drilled higher in the structure on a separate segment, was to prove petroleum in Upper Jurassic rocks and in Triassic rocks. The well encountered a 112-foot (34-meter) gross gas column in Jurassic rocks with poorer reservoir quality than expected. ConocoPhillips needs to further evaluate the well results to calculate the size of the discovery. ConocoPhillips is the operator of Production License 301 CS, holding a 22% interest. The other licensees on the field include OMV (30%), Dong (28%), and Talisman (20%).
Project Details: Peking Duck
Mediterranean
NZOG Farms-In to Tunisian Concession
Dec 14, 2011 – New Zealand Oil & Gas signed an agreement to acquire a 40 percent stake in a Tunisian concession containing the Cosmos South oil field. The Cosmos Concession is located in the Gulf of Hammamet, offshore Tunisia. The concession was held by a joint venture consisting of Storm Ventures International (80 percent, operator) and L’Enterprise Tunisienne d’Activites Petrolieres (20 percent). Storm, a wholly-owned subsidiary of Chinook Energy, will reduce its share of the concession to 40 percent under the farm-in agreement. A development plan is being prepared, and if approved through a Final Investment Decision, NZOG will pay the first US $19MM of Storm???s share of the development costs. The development plan is based on three wells, a small platform and an FPSO, with initial production rates targeted at 15 to 20M barrels of oil per day. A decision on the FID is slated for mid-2012, and if approved, first oil production is anticipated for mid-2014. Independently evaluated proved and probable oil reserves of 6.3 MMbbl have been attributed to the Cosmos South Block, with the potential of additional capacity from adjacent lobes. These reserves will be further assessed before the submission of the FID. The discovery was made in 1983, with a smaller adjacent discovery made in 1985. The water depth of the site is 394 feet (120 meters).
S. America – Brazil

OGX Plans to Flow Oil from Campos Basin in 1Q12
Dec 15, 2011 – OGX has pushed the date of first oil back from the OSX-1 FPSO until January. The company expects the FPSO and offloading tanker to leave the port of Rio de Janeiro on Christmas day, and anticipates for production to commence on January 23. Furthermore, preparatory work in the Waimea field was carried out. The Waimea field is located 37 miles (60 kilometers) off the coast of Rio de Janeiro in water depths ranging from 394 to 459 feet (120 to 140 meters).

Worldwide: Project Field Development News

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Worldwide Field Development News
Dec 2 – Dec 8, 2011
This week the SubseaIQ team added 2 new projects and updated 17 projects. You can see all the updates made over any time period via the Project Update History search. The latest offshore field develoment news and activities are listed below for your convenience.

Mediterranean
Northern Obtains Seismic Data from Adriatic Sea
Dec 7, 2011 – Northern Petroleum completed a 148,263-acre (600 square kilometer) 2D seismic survey offshore Southern Adriatic covering two licenses, F.R39.NP and F.R40.P. Seismic acquisition began last month using the vessel ‘M/V Princess’ contracted from CGGVeritas S.AA. Completion of the acquisition occurred within the prescribed six-day period. The work program, including this seismic acquisition, aims to obtain complete and better quality data to improve definition of the promising prospects identified from older seismic surveys. A further 3D seismic is planned in 2012 and will commence once approvals are obtained from all relevant authorities. The F.R39.Np and F.R40.P permits include the Rovesti and Giove oil discoveries and 10 mapped prospects. Northern and partner, Azimuth, intend to define and delineate suitable appraisal and exploration drilling targets.
Europe – North Sea
Det norske Gets Nod to Drill Wildcat Well 25/6-4 S
Dec 7, 2011 – The Norwegian Petroleum Directorate has granted Det norske a drilling permit for well 25/6-4 in the Norwegian sector of the North Sea. The Songa Delta (mid-water semisub) will drill the well in 114 meters of water. The drilling program for well 25/6-4 S applies to the drilling of a wildcat well in Production License 414. Det norske is the operator of the license with a 40 percent interest. Partners in the license include Faroe (20 percent), Bayerngas (20 percent) and Noreco (20 percent).
Centrica Successfully Appraises Butch Discovery
Dec 7, 2011 – Centrica announced that appraisal results at its Butch exploration well have indicated a significant presence of light oil in the reservoir. The operator said preliminary resource estimates specify a discovery of between 30 to 60 MMboe for the main Butch segment. Further data collection is now underway and the drilling of a second sidetrack well has commenced on the Butch southwest compartment, where the well is targeting additional volumes. The discovery lies in 217 feet (66 meters) of water and is close to existing infrastructure. Centrica Energi has a 40 percent operating interest in Butch discovery; while Suncor Energy holds 30 percent; Spring Energy holds 15 percent and Faroe Petroleum holds 15 percent.
Project Details: Butch
Total Acquires GDF Suez’s Stake in Elgin/Franklin
Dec 7, 2011 – Total has purchased GDF Suez’s share in the Elgin, Franklin fields (this participation is held through a 22.5 percent stake in the company, Elgin Franklin Oil & Gas). By giving Total control of the whole of the capital of EFOG, which it previously held 77.5 percent, this acquisition increases its share in the Elgin/Franklin fields from 35.8 percent to 46.2 percent. Following the completed transaction, the partners in Elgin/Franklin will be EFOG (Total 100 percent) 46.2 percent; Eni 21.87 percent; BG 14.1 percent; E.ON Ruhrgas 5.2 percent; Esso Exploration & Production 4.4 percent; Chevron 3.9 percent; Dyas 2.2 percent; and Summit Petroleum 2.2 percent. The Elgin/Franklin development produces approximately 140,000 boed. Located in the Central Graben area of the UK North Sea about 149 miles (240 kilometers) east of Aberdeen, the Elgin and Franklin fields are 4 miles (6 kilometers) away from each other in waters measuring 305 feet (93 meters).
Project Details: Elgin/Franklin
Antrim Hits Pay in Erne Well
Dec 7, 2011 – Antrim Energy has made a discovery in the Erne exploratory well, 21/29d-11, in the UK sector of the North Sea. The well reached a total depth of 5,562 feet (1,695 meters), encountering a gross hydrocarbon column in excess of 50 feet (15 meters) in the Eocene Upper Tay sandstone. This includes 20 feet (6 meters) of net oil pay and 10 feet (3 meters) of net gas pay, with average porosity exceeding 30 percent, and average hydrocarbon saturation of about 80 percent. The operator will now drill a sidetrack well from the pilot hole to further delineate the reservoir. Erne is located in Block 21/29d in the UK sector of the North Sea. Antrim Energy operates Block 21/29d.
Project Details: Erne
Statoil Gets Nod to Drill in Barents Sea
Dec 5, 2011 – The Norwegian Petroleum Directorate has granted Statoil a drilling permit for wellbore 7220/7-1 in the Barents Sea. The Aker Barents (UDW semisub) will drill the well. The drilling program applies to the drilling of a wildcat well in Production License 532. Drilling will occur about 62 miles (100 kilometers) northwest of the Snohvit field. Statoil serves as the operator of the permit with a 50 percent interest. The other licensees are Eni (30 percent) and Petoro (20 percent).
Statoil Reaches Investment Decision for Visund North
Dec 5, 2011 – Statoil and partners have reached an investment decision for the Visund North development in the North Sea. Recoverable reserves are expected to be 29 MMbbl of oil equivalents, consisting mainly of oil. The development entails a standard seabed template with two wells, to be manufactured by FMC, and installed in the summer of 2012. The oil will transport to Visund A through a new pipeline system, for processing on the platform. Statoil says that all of the main contracts have been awarded, apart from marine installations and platform modifications. These are planned to occur by the end of the year. Production is slated for 2013. The oil and gas field is located in Blocks 34/8 and 34/7, which Statoil operates.
Project Details: Greater Gullfaks Area
Providence Receives Exploration License 2/11
Dec 2, 2011 – Providence has acquired Standard Exploration License 2/11 in the Kish Bank Basin, offshore Dublin. The granted license has a time period of up to six years and is split into two three-year phases. The license is a successor authorization to the previous License Option 08/2. License 2/11 contains the Dalkey Island exploration prospect, which the partners have committed to drill during the first phase. The partners have recently commenced the application process for a foreshore license over the area in order to carry out well site survey and drilling operations. Providence operates the license with a 50 percent interest.
Project Details: Dalkey Island
N. America – US GOM
FMC Technologies to Deliver Subsea Equipment for Who Dat Field
Dec 8, 2011 – FMC Technologies has signed an agreement with LLOG Exploration Limited for the design, manufacture and supply of subsea production systems for the Who Dat development in the GOM. FMC’s scope of supply includes seven subsea production trees and control systems. Delivery of the equipment is slated for 2012. The Who Dat field, situated in 3,000 feet (914 meters) of water, is expected to commence production in 3Q11. LLOG operates the field with a 67.5 percent interest.
Project Details: Who Dat
S. America – Other & Carib.
FOGL to Spud Loligo in Late April/Early May
Dec 7, 2011 – FOGL announced that the Leiv Eiriksson (mid-water semisub) has left Greenland and is now en route to the Falkland Islands for the upcoming B&S and FOGL drilling program. The company plans to spud the Loligo prospect in late April or early May 2012, and the second well to spud on completion of Loligo. Loligo is a Tertiary Channel play structure with estimated Pmean reserves of 4.7 Bbbl. The Loligo complex comprises several reservoir objectives along with a number of various reservoir targets. The well is located in the Falkland Islands.
S. America – Brazil
ANP Orders Chevron to Shut-In Well at Frade Development
Dec 2, 2011 – The National Petroleum Agency has ordered Chevron Brasil Upstream to shut-in one production well and four water injection wells at the Frade FPSO offshore Brazil. ANP submitted this requested after conducting a safety audit of the vessel and found that sulfide gas has been leaking. The closed production well accounts for less than 10 percent of the field’s total production output of about 79,000 bopd, stated the operator. The field is situated in the Campos Basin in approximately 3,700 feet (1,128 meters) of water, roughly 230 miles (370 kilometers) northeast of Rio de Janeiro. Frade is a subsea development with wells tied-back to the Frade FPSO.
Project Details: Frade
Africa – West
Vanco Makes a Discovery in Independence-1X Well
Dec 7, 2011 – Vanco Cote d’Ivoire and partners have made a discovery in the Independence-1X exploratory well in Block CI-401. The discovery has penetrated the targeted objective and found a series of good-quality sandstones containing light oil. Full review of well results, including wireline logs, reservoir pressures and fluid samples, confirm that the well penetrated 8 meters (26 feet) of hydrocarbon pay in good-quality Turonian-aged sand package. Recovered hydrocarbon samples from Independence-1X well indicate the oil registers at 40 degree API gravity. The operator will temporarily abandon the well at a total depth of 13,556 feet (4,132 meters). The Ocean Rig Olympia (UDW drillship) drilled the well in a water depth of 5,541 feet (1,689 meters). Vanco (Operator) holds a 28.34 percent participating interest.
Asia – SouthEast
Lundin Spuds Bertam-2 Offshore Malaysia
Dec 8, 2011 – Lundin Petroleum has spud the Bertam-2 appraisal well in PM307 Production Sharing Contract area, offshore Peninsular Malaysia. The total depth of the well is 6,194 feet (1,888 meters) and is being drilled by the Offshore Courageous (400’ ILC) jackup. The objectives of the well are to appraise and test the Oligocene lower coastal plain sandstones of the PM307 PSC area, and to test the continuity and quality of the K10 oil reservoir. The operator will also explore the deeper sands in an independent closure on the northern side of the structure. Discovered in 1995, the Bertam well hit oil in the K10 sandstone reservoir. While conducting a flow test, the well produced 34 degree API oil at a rate of 624 bopd. Bertam-2 is located to the northeast of the discovery well in 249 feet (76 meters) of water. PM307 PSC is operated by Lundin Malaysia with a 75 percent interest; Petronas holds the remaining interest.
Australia
AWE Sells BassGas Stake to Toyota Tsusho
Dec 8, 2011 – AWE Limited will sell an 11.25 percent stake in T/L1, and a 2.75 percent interest in T/18P in the BassGas project to Toyota Tsusho for a cash consideration of A$80.125 million. The T/L1 permit includes the Yolla gas and condensate field and its associated production infrastructure, and a 2.75 percent interest in T/18P, which includes the Trefoil gas and condensate discovery. Once the agreement is finalized, AWE will hold a 46.25 percent interest in T/L1 and a 44.75 percent interest in T/18P.
Project Details: BassGas Project
Chevron, FMC Team Up for Subsea Equipment for Wheatstone
Dec 8, 2011 – Chevron granted FMC Technologies a contract for the design, manufacture and supply of subsea production systems to support the Wheatstone project. The scope of supply includes 11 subsea production trees, 11 wellheads, three manifolds, subsea and topside controls and well access systems. Delivery of the equipment is scheduled to commence in 2013. The Chevron-operated Wheatstone project, situated offshore Australia, compromises the Wheatstone and Iago gas fields, located in water depths between 330 and 850 feet (100 to 260 meters).
Project Details: Wheatstone
Eni Commences 3D Seismic over Blackwood
Dec 7, 2011 – Eni has commenced a Bathurst 3D seismic survey over the Blackwood East area of permit NT/P68. The field acquisition program is scheduled for completion within 50 days. Under the terms of the farm-in agreement, Eni will pay MEO’s share of the costs to acquire and process the 3D seismic survey. The company will have 365 days from completion of the acquisition to elect whether or not to exercise its option to drill, and pay 100 percent of the cost of the Blackwood-2 well in order to retain its 50 percent interest in the gas discovery. The CGG Veritas seismic vessel, M/V Veritas Viking II is acquiring the 172,480-acre (698-square kilometer) seismic survey.
Project Details: Blackwood
Eni Purchases Additional Interest in Evans Shoal Field
Dec 7, 2011 – Eni has purchased a 32.5 percent stake in the Evans Shoal gas field in the Timor Sea, Australia. The undeveloped field, discovered in 1998, holds expected gas-in-place of up to 7 Tcf. Subject to completion of the purchase of Santos-interests, in a separate transaction, Eni has agreed to sell a 7.5 percent equity share in exploration permit NT/P48 to Shell. Both transactions are subject to the regulatory authority. Following the approved transaction, the partners in the revised NT/P48 joint venture will consist of Eni (32.5 percent, operator), Petronas (25 percent and Osaka Gas (10 percent). The Evans Shoal gas field is located in the NT/P 48 exploration permit in the Bonaparte Basin.
Project Details: Evans Shoal
Apache Brings Reindeer/Devil Creek Project Online
Dec 7, 2011 – Apache has commenced production from the Reindeer field in the Carnarvon Basin. The delivery of the gas is being processed at the new onshore Devil Creek plant near Karratha. The Reindeer/Devil Creek development includes the installation of an offshore unmanned wellhead platform in the Reindeer field, a 105-kilometer pipeline to shore and the development of the gas plant. The Devil Creek gas plant has a gross production capacity of 215 TJ/day and is initially planned to ramp up to sales of 120 TJ/day. The Reindeer gas field is located in the Carnarvon Basin, offshore Western Australia in waters measuring 203 feet (62 meters) within exploration permit WA-209-P. Apache Corporation holds a 55 percent operating interest, and Santos holds the remaining 45 percent interest.
Project Details: Reindeer-Devil Creek Project

UK Gov’t Approves USD 3.3 Billion Golden Eagle Development

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Nexen Petroleum UK Ltd., a subsidiary of Nexen Inc., announced today it has received approval from the UK Department of Energy and Climate Change (DECC) to proceed with the Golden Eagle area development – a GBP 2 billion (C$3.3 billion) investment (GBP 750 million net to Nexen) that is expected to produce an estimated 140 million barrels of oil equivalent (gross) of proved and probable reserves over an 18-year period.

The Golden Eagle development encompasses both the Golden Eagle and Peregrine reservoirs located in central North Sea blocks 20/1N, 20/1 and 14/26a, approximately 43 miles from Aberdeen. The development plan for Golden Eagle incorporates a combined production, utilities and accommodation platform linked to a separate wellhead platform. Plans call for 20 development wells (16 platform-based and four subsea) to be drilled. The development will also include associated in-field and export pipeline infrastructure.

Detailed design engineering has commenced and fabrication is scheduled to start in late 2011. Pipeline and subsea installation is expected to begin in early 2013, to be followed by drilling later that same year. First oil production is forecast for late 2014 and the development is expected to have an initial gross production rate of up to 70,000 barrels of oil equivalent per day (boe/d), about 26,000 boe/d net to Nexen.

“This is a great day for the UK oil and gas industry. Regulatory approval marks a major milestone in the development of Golden Eagle, which is one of the largest oil discoveries in the UK North Sea since our Buzzard discovery,” said Phil Oldham, Managing Director of Nexen Petroleum UK Ltd.

During construction, the Golden Eagle development is expected to create employment for more than 2,000 workers. Once operational, the facility is expected to employ more than 400 people and provide thousands of indirect jobs throughout its 18-year production life. More than two-thirds of the contracts for products and services for Golden Eagle are to be sourced in the UK, a total benefit estimated at more than GBP 1.4 billion.

The project’s design, construction and operation will reflect the results of a comprehensive environmental impact assessment, which has also been approved by the DECC.

“Continuous improvement in safety and environmental performance has been built into our project planning. Safe, responsible energy development is our priority,” said Oldham.

Nexen holds significant acreage adjacent to the Golden Eagle development and continues to explore and appraise the UK North Sea to identify future opportunities and potential synergies with the Golden Eagle infrastructure. This includes participating in an active UK North Sea exploration and appraisal campaign and investing in other development projects in the region.

Nexen is the second largest oil producer in the UK. In 2010, the company’s UK-based business produced approximately 110,000 boe/d, primarily from the Buzzard field. The company currently provides employment for about 1,200 full-time and contract staff at its offices in Uxbridge and Aberdeen and at its offshore facilities.

Nexen Petroleum UK Ltd. is the operator of Golden Eagle and holds a 36.54% working interest in the field. The remaining interest is held by Maersk Oil North Sea UK Ltd. (31.56%), Suncor Energy UK Ltd. (26.69%) and Edinburgh Oil and Gas Ltd. (5.21%).

Nexen Petroleum UK Ltd. is a subsidiary of Nexen Inc., a global energy company listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the UK North Sea, offshore West Africa and deepwater Gulf of Mexico.

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