OGJ Newsletter

Jan. 28, 2008
General Interest - Quick Takes

WEF forecasts energy supplies as key risk

Stable global energy supplies will be a major risk area for countries in 2008, according to a report published by the World Economic Forum (WEF), signaling that the issue is facing the highest levels of political and economic uncertainty in a decade.

WEF, speaking in advance of its annual event in Davos Jan. 23-7, said that new thinking and concerted action by business leaders and public policymakers were critical to address the problem. Fossil fuel supplies are expected to become tighter over the next 2 decades, and more price shocks are likely to happen.

The report—produced together with a group of insurers and finance experts—said that securing energy supplies and cutting carbon emissions simultaneously will be difficult to achieve.

“With predictions of a 37% increase in oil demand over current levels by 2030, the report sees limited scope for a fall in energy prices over the next decade,” WEF reported. “This may be good news for oil and gas producers, but it creates an inherent mismatch between those who bear risk and reward, which should be addressed through better dialogue at all levels,” the group added.

David Nadler, vice-chairman of Marsh & McLennan Cos. USA, one of the contributors, said: “A move towards a forward-looking regulatory framework is needed in order to ensure long-term economic viability. This framework should seek to unlock investment and innovation in cleaner energy and, ultimately, deliver an economic price for carbon.”

E&Y: UK reliance on gas for power to hit 65% 2025

The UK’s reliance on natural gas for electric power generation will soar to as much as 65% by 2025 if the government doesn’t fully implement its new proposed energy bill, Ernst & Young warned in a recent report.

E&Y said the UK’s security of supply could be jeopardized as gas imports rise due to falling domestic supplies. The report said, “Inaction and investment by default solely in [combined-cycle gas turbines] could see the UK’s dependence on gas increase by as much as 30% to 2025.”

Included in the energy bill, published earlier this month, the UK government paved the way for a new generation of nuclear power plants by inviting private companies to carry out projects (OGJ Online, Jan. 14, 2008). Failure to stimulate the building of new nuclear capacity, according to the report, would effectively commit the UK to a “no nuclear” future by 2025.

Tony Ward, E&Y utilities director, said energy companies will have to invest as much as £45 billion by 2025 to develop nuclear and clean coal projects to meet the UK’s needs. This would be £17 billion more than an alternative mix with unrestricted expansion of gas-fired capacity.

However, burdensome planning rules and regulatory uncertainty remain barriers to potential investment, and these must be changed, the report noted.

UK lease round acreage holds large oil potential

Acreage on offer in the upcoming UK licensing round holds a potential of 17 billion bbl, according to a study by North Sea consultancy Hannon Westwood.

The government plans to launch the 25th licensing round with the largest number of blocks to date, and it will close by the end of April. Hannon Westwood said this bidding round “has the potential to add 648 million boe through discoveries and 16.6 billion boe thorough prospects to the UKCS asset pool.”

Examining unlicensed blocks and partial blocks, the report said that there were 36 discoveries, which hold 648 million boe of gross unrisked potential reserves, of which are 389 million bbl oil and 1.55 tcf of gas.

There are 275 prospects within the blocks, and these hold an estimated 16.6 billion boe of unrisked potential reserves. Prospects hold 11.8 billion bbl of oil and 28.6 tcf of gas.

The potential resource in the study compares to 7.5 billion boe in discoveries and about 50 billion boe unrisked, undrilled in exploration prospects in licensed and unlicensed acreage, according to Hannon Westwood’s database.

During the last 12 months, exploration and appraisal activity on the UK Continental Shelf had reached record levels over the past 10 years, the study said. In 2007, 65 vertical wells were spudded. Hannon Westwood estimates that there are another 3 years of drilling at the current pace because there are more than 220 exploration and appraisal wells planned for 2008-10.

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Exploration & Development - Quick Takes

Deepwater gas find gauged north of Tobago

The first well on deepwater Block 22 in the Caribbean north of Tobago Island is a large gas discovery, said operator Petro-Canada.

The Cassra-1 wildcat in 1,411 ft of water on the northwest edge of a 26-sq-mile seismic amplitude anomaly flowed at an equipment restricted rate of 23 MMcfd from a 30-ft interval in an undisclosed formation. The well went to TD of 5,617 ft and established a gas-water contact for the anomaly.

Petro-Canada said, “Based on the well results and using local field analog recovery factors, our seismic model indicates the discovery could contain in the range of 0.6 to 1.3 tcf of recoverable contingent resources.” Appraisal is required to finalize the estimates.

Petro-Canada said the discovery validates its exploration model.

The Diamond Offshore Ocean Worker semisubmersible is to move 2.8 miles south to drill Cassra-2, which as part of its objective will appraise the Cassra-1 discovery. Then it will drill two to three other prospects on Block 22 in an expected five-well 2008 drilling program.

Block 22 shareholders are Petro-Canada 90% and Petroleum Co. of Trinidad and Tobago 10%.

The Cassra discovery is 75 miles east-northeast of the North Coast Marine Area, where Petro-Canada produces a net 65 MMcfd to its 17.3% interest in a project that supplies gas for the Atlantic LNG project.

Petro-Canada is also carrying out a multiwell exploration program on Blocks 1a and 1b in the Gulf of Paria, where it holds 80% interest.

Gas-condensate find tested east of Trinidad

A group led by Canadian Superior Energy Inc., Calgary, gauged a gas-condensate discovery on Block 5(c) 60 miles off Trinidad and Tobago’s east coast.

At least one uphole zone remained to be tested at the Victory-1 well, while the first formation flowed at restricted rates of 40-45 MMcfd with 30 bbl/MMcf of condensate. Canadian Superior, without giving figures, said, “The flowing wellhead pressure on a restricted basis and bottomhole pressures are comparable or better than other producing wells and fields in the immediate area.”

The well, the first in a three-well exploration program on the block, is on the 80,000-acre Intrepid Block just east of Dolphin gas field and 3 miles from a pipeline to shore. TD is 16,150 ft. The Bounty prospect is next, to be followed by Endeavour.

The other participants are BG International Ltd. and Challenger Energy Corp., another Calgary independent.

Exploration due on Trinidad land blocks

Two Canadian independents will prospect on 214,000 acres in the underexplored Central Range in central Trinidad.

Petro Andina Resources Inc., Calgary, plans to acquire a 50% working interest from Voyager Energy Ltd., a private Calgary firm, and become operator of the onshore Central Range Shallow and Central Range Deep blocks. Drilling is likely to begin in 2009.

The blocks are subject to production-sharing contracts, and the deal is subject to approval by the Trinidad and Tobago government. The government awarded the blocks to Voyager on Jan. 10.

Petroleum Co. of Trinidad & Tobago has the right to participate for a 35% working interest in any development on the shallow block and for a 20% working interest in any development on the deep block.

The PSCs provide for an initial 4-year exploration phase with 2-year extension options.

The PSCs apply to hydrocarbon rights above and below 4,500 ft true vertical depth, respectively. They have work obligations of 100 line-km of 2D seismic, 250 sq km of 3D seismic, one well to at least 12,000 ft, and three wells to 4,500 ft or less.

Petro Andina and Voyager will each pay a $2.75 million signature bonus upon final government approval, and Petro Andina will carry the first $5 million of Voyager’s seismic acquisition costs in the exploration phase.

Petro Andina estimated its 2008 capital spending in Trinidad and Tobago will total $15 million, mostly for seismic surveying.

Norway expecting more exploration drilling

Operators are expected to drill 35-40 exploration wells on the Norwegian Continental Shelf in 2008, the Norwegian Petroleum Directorate said.

NPD reported 32 wells were spudded last year, resulting in 12 small discoveries. Of the 32 total, 20 were wildcat wells and 12 were appraisal wells.

High oil prices encouraged operators to significantly increase their activities, but this also meant that costs soared too.

“Continued growth in total investment costs is expected,” NPD officials said. The shelf produced 1.5 billion boe in 2007, which was 164 million boe less than the record set in 2004.

One problem with exploration growth was the impact on the environment where emissions and discharges rose.

The NPD approved eight plans for development and operation (PDO) for 9 new deposits in 2007. Around 10 PDOs are expected to be submitted to the authorities in 2008. However, gas production rose in 2007 while oil production fell compared with 2006.

Production started from four oil and gas fields: Blane, Enoch, Ormen Lange, and Snohvit.

An additional three fields are expected to start producing in 2008: Alvheim, Vilje, and Volve.

During 2007, NPD collected 2,617 km of seismic data in the Nordland VII and Troms II areas, and it will shoot more data this summer.

StatoilHydro submits Yttergryta development plan

Gas production from Yttergryta field, which lies 33 km east of Asgard B platform in the Norwegian Sea, will start in first quarter 2009. This is according to the plan of development and operation (PDO) that was submitted Jan. 18 to the Norwegian energy ministry.

Yttergryta is expected to produce 1.75 billion cu m of gas over 3-5 years. StatoilHydro will invest 1.2 billion kroner in the project, including drilling expenses. The ministry is expected to take as long as 8 weeks to review the PDO.

Operator StatoilHydro said Yttergryta will be developed with a subsea template tied back to the Asgard B platform, sending 3.5 million cu m/day of gas via the Asgard gas pipeline to the processing plant at Karsto.

The exploration well that was drilled in June 2007 will be converted to a production well in 2008, StatoilHydro said, and the template for the subsea production facility has already been installed.

StatoilHydro holds a 45.75% interest in the project. Other licensees are Total SA 24.5%, Petoro 19.95%, and Eni SPA 9.8%.

CNX spending to target eastern US shales

CNX Gas Corp., Pittsburgh, said its 2008 capital budget includes exploration for gas in Marcellus, Huron, Chattanooga, and New Albany shales and the Trenton-Black River dolomite in the eastern US.

The overall plan is for a 35% spending increase to $470 million, of which $377 million will go toward the drilling, midstream, and land operations in the company’s Virginia and Pennsylvania coalbed methane development projects.

CNX Gas will drill 300 CBM development wells in Virginia, 100 in Mountaineer, and 100 in Nittany. Each exceeds the 2007 program.

The other $88 million includes $27 million for CBM exploration, $46 million for shale and other exploration, and $15 million for land. Some conventional sand horizons will be tested for the presence of oil.

The company sees shale potential in the Marcellus on 16,000 acres in New York, 41,000 acres in Pennsylvania, 26,000 acres in West Virginia, and 78,000 acres in Ohio; in the Huron shale on 193,000 acres in Kentucky and West Virginia; in the Chattanooga shale on 132,000 acres in Tennessee; and in the New Albany shale on 300,000 acres in Kentucky, Indiana, and Illinois.

Drilling & Production - Quick Takes

Pemex lets $683 million contract to Halliburton

Mexico’s Petroleos Mexicanos has let a 3-year, $683 million contract to Halliburton Co. to manage the drilling and completion of 58 land wells in the southern region of Mexico.

The contract spans a number of well conditions, including depressurized and high-pressure/high-temperature formations, combined with complex geologies and tremendous depths, ranging 3,500-6,500 m.

Halliburton’s project management group will provide wellbore-cementing tools, stimulation equipment and wireline technology, as well as drilling fluids, drill bits, directional-drilling services, and completion tools.

Petrobras lets contracts for gulf fields

Petroleo Brasileiro SA subsidiary Petrobras America has awarded two major contacts worth a total $300 million to Technip for the development of the Cascade and Chinook gas fields in the Walker Ridge area of the Gulf of Mexico. The fields lie in 8,200 ft and 8,800 ft of water, respectively.

The first contract covers the engineering, procurement, construction and installation of five free-standing hybrid riser systems for both Cascade and Chinook fields.

The second contract covers the installation of the Cascade infield flowlines and gas export pipeline and includes: welding of about 120 km of 6-in. and 9-in. steel pipelines, design and fabrication of 10 pipeline end termination and 2 inline tees, and installation of the pipelines and associated structures.

Offshore installation is slated to begin in third quarter 2009, using Technip’s Deep Blue and Constructor vessels.

Mobil to upgrade Nigerian production facilities

Mobil Producing Nigeria, a unit of ExxonMobil Corp., has let a $220 million contract to a consortium led by AMEC PLC for upgrade work for its oil and gas production facilities in southeast Nigeria over the next 5 years.

AMEC has teamed with Jagal and Netco to manage the project, provide services, and prepare engineering designs to extend the lifespan of production facilities. An AMEC spokesman told OGJ that it hadn’t been yet given data on expansion increases as this was a long-term project.

Mobil has more than 800,000 acres in shallow water and production comes from 90 offshore platforms, with 283 flowing completions in 353 wells with a production capacity of about 720,000 b/d of crude, condensate, and natural gas liquids.

Chevron taps Atwood for semi newbuild

Chevron Australia let a contract to Atwood Oceanics Inc. for the construction of a semisubmersible drilling unit for a period of at least 3 years, with an option for up to 6 years.

The rig will be moored in as much as 6,000 ft of water with its own mooring equipment, but could work an additional 2,000 ft using prelaid mooring equipment.

The operating cost of the rig will be $470,000/day for 3 years and, subject to cost escalation provisions in the contract, it may increase.

Atwood said the total cost of the rig, including administrative and overhead costs and capitalized interest, will be $570-590 million.

Atwood executed a construction contract with Jurong Shipyard Pte. Ltd. to construct the drilling unit at Jurong’s Singapore shipyard, with delivery expected in early 2011.

A Chevron spokesman said the contract underpins Chevron Australia’s long-term commitment to find, appraise, and develop Australian gas resources for domestic and international markets.

Silverstone taps Acergy for Victoria field lines

Silverstone Energy Ltd. granted a £9 million contract to Acergy SA to install the flowline, control umbilical, and other subsea equipment in Victoria gas field in the southern North Sea. Production is due to start by yearend.

Acergy will tie the field back to the Viking BD platform via Vixen, operated by ConocoPhillips.

Reserves to be recovered under Phase 1 are estimated at 36 bcf of gas. The field will be developed through reentry of the discovery well on Block 49/17. The Victoria facilities have been set up to enable rapid development of the additional fault blocks that make up the Victoria and Viking B extension, subject to performance of Phase 1, Silverstone said.

Silverstone will export gas over 130 km through the Viking subsea pipeline to the Theddlethorpe gas terminal onshore in Lincolnshire. At least another four exploration wells are scheduled over the next 12 months.

Silverstone was founded 3 years ago. Operator of the project with a 50% stake, it will work with partners BP PLC and ConocoPhillips.

Processing - Quick Takes

CSB team visits BP’s Texas City refinery

The US Chemical Safety Board has dispatched a team to BP America Inc.’s Texas City, Tex., refinery to investigate a Jan. 10 process-related accident that killed an employee.

Refinery officials told CSB on Jan. 17 that a chemical explosion may have been involved in the ultracracker unit’s overpressure event that led to the employee’s death. Earlier reports indicated that water pressure was responsible, CSB said.

CSB said its team, which was slated to arrive on site on Jan. 18, will be led by CSB Supervisory Investigator Don Holmstrom, who led the agency’s 2-year investigation of the 2005 fire and explosion at the refinery.

William Joseph Garcia, a shift foreman who had worked at the refinery for 32 years, was killed on Jan. 10 when a metal lid flew off of a water-protection vessel that was attached to the ultracracker, according to initial reports.

EC approves Petroplus’s refinery acquisitions

The European Commission has approved Petroplus Holdings AG’s $875 million proposal to buy two refineries from Shell International Petroleum Co. Ltd. in France, indicating that the deal will close in the second quarter.

Petroplus Holdings wants to buy the 164,000 b/cd Petit Couronne and 80,000 b/cd Reichstett Vendenheim refineries.

Petit Couronne, 130 km northwest of Paris on the Seine River, produces 40% middle distillates and 20% gasoline. The Reichstett Vendenheim refinery is in Alsace and produces 45% middle distillates and 20% gasoline.

Transportation - Quick Takes

Gazprom to acquire Serbian NIS

Serbia was reported Jan. 22 as having agreed to sell OAO Gazprom a controlling interest in state oil company NIS. Terms of the deal were not disclosed, but Gazprom in December 2007 offered €400 million for a 51% stake in the company. At the time, Gazprom also promised an additional €500 million of investment and that it would route the South Stream pipeline through Serbia.

South Stream is a €10 billion gas pipeline project, running 558 miles under the Black Sea via Bulgaria to Italy. Gazprom and Italy’s ENI SPA reached commercial terms on the project in December. Feasibility and marketing studies on the 30 billion cu m/year project are under way, to be completed by yearend. Initial plans call for construction to begin in 2009, with an in-service date of 2013.

Gate LNG awards terminal construction contract

Royal Vopak and NV Nederlandse Gasunie, project operators of the planned 9 billion cu m/year Gate liquefaction terminal at Rotterdam, have awarded a turnkey contract to Sener Ingenieria y Sistemas SA and Techint Group to jointly construct the terminal. The value of the contract was not disclosed.

The €800 million plant will take 4 years to construct. Sener and Techint will perform detailed engineering and oversee purchasing, construction, and start-up.

Entrepose Contracting and Vinci Construction PLC—both also participating in the venture—will design and build the three 180,000 cu m LNG tanks, which will have an emission capacity of 9 billion cu m/year of gas. Two tanks of the same size will be added later.

Gate LNG initially will have a jetty for LNG ships having capacities as great as 267,000 cu m. A second jetty will be built at a later date.

Gate will have a greater capacity than the average European LNG plant, a Sener executive said.

Dong Energy, EconGas, and Essent, initial customers for long-term throughput agreements, will each take 3 billion cu m/year.

New shareholders in the terminal are Dong Energy, Essent, and OMV Gas International (as a major shareholder of EconGas), which will each acquire a 5% equity stake.

Afren consortium to study Nigerian LNG plant

Afren PLC, E.On Ruhrgas AG, and African LNG Holdings Ltd. will assess the feasibility of building an LNG plant and related gas facilities in southeastern Nigeria.

The partners will focus on developing gas from a targeted list of assets and will study gas gathering capabilities and potential LNG export possibilities. Afren said the group will then decide on establishing joint corporate structures and funding arrangements.

Under a cooperation agreement the consortium signed Jan. 22, analyses will focus on the Anambra basin and will aim to reduce gas flaring and ensure that domestic demand can be satisfied and export commitments met.

African LNG will be Afren’s exclusive downstream liquefaction partner in developing a monetization strategy.

EnCana plans 22-mile Colorado gas pipeline

EnCana Oil & Gas Inc. filed a right-of-way application for the construction of a 22-mile natural gas pipeline with the US Bureau of Land Management’s field office in Grand Junction, Colo., BLM reported on Jan. 18.

BLM said the proposed 32-in. line in the Colbran and Plateau Valley area would transport as much as 650 MMscfd of field-grade gas for further processing and delivery to markets.

About 93% of the proposed line would be at the edge of existing pipeline or road corridors. It would begin on Hayes Mesa in the Anderson Gulch area about 5 miles west of Colbran and end at EnCana’s Orchard Unit compressor near Interstate 70 about 6 miles northeast of De Beque, BLM said.

BLM’s Grand Junction office has been designated lead office for the project and will be preparing an environmental impact statement under the National Environmental Policy Act. It will accept public comments through Feb. 18 to identify issues and concerns to consider during the environmental review, BLM said.