Kazakh officials suspend Kashagan field permit
Kazakhstan officials Aug. 27 suspended the permit for exploration and development work in Kashagan oil field off Kazakhstan, effectively halting work on the vast field for the next 3 months.
This is the latest in a series of obstacles that the consortium behind Kashagan’s development-led by Agip Kazakhstan North Caspian Operating Co. NV (Agip KCO), a unit of Italy’s Eni SPA-has had to contend with. Most recently work in Kashagan was snagged by alleged environmental violations that threatened to revoke the consortium’s license (OGJ, Aug. 27, 2007, p. 26).
Eni is sole operator and holds an 18.52% interest in the North Caspian Sea production-sharing agreement to carry out exploration, development, and production activities in an offshore area in the northern part of the Caspian Sea, where giant Kashagan field was discovered.
To carry out operations, Eni created Agip KCO, which acts on behalf of the consortium.
The group plans to develop the field by drilling about 280 wells and building offshore platforms and artificial islands.
Oil and part of the natural gas produced will be sent in two separate trains to the treatment plant of Bolashak near Atyrau. Export options for production being considered include using an oil pipeline owned and operated by Caspian Pipeline Consortium, in which Eni holds a 2% interest, that links Atyrau, in Kazakhstan, to the Russian oil terminal of Novorossisysk, in the Black Sea.
Eni also is cooperator and holds a 32.5% interest in Karachaganak Petroleum Operating BV, a consortium created to develop and operate Karachaganak field, one of the world’s largest oil and gas fields, in northwestern Kazakhstan.
Ryder Scott: Trinidad and Tobago reserves declining
The Ryder Scott audit of Trinidad and Tobago’s natural gas reserves has revealed a 3.83 tcf decline since January 2005.
The report found that Trinidad and Tobago has 17.05 tcf of proved gas reserves, 7.76 tcf of probable reserves, and 6.23 tcf of possible reserves.
The report also found that the twin-island nation’s risked 3P reserves would be adequate to supply the demand for gas through 2016 before declining.
Trinidad and Tobago’s cabinet made four decisions arising from the survey results, according to Energy Minister Lenny Saith:
- Increase the rate at which decisions are made and blocks awarded for exploration.
- Do not move any gas-based project to the priority A category from the nonpriority B category.
- Get more geological information on potential areas to explore.
- Look at the taxation structure for exploration in high-risk areas.
Saith said, “The survey is saying, ‘Look at your taxation for exploration in high-risk areas, not exploration in low-risk areas. Look at your tax policy and determine if there is anything you need to do that will speed up [companies’ willingness] to take risk in those high risk areas.’”
Saith said 16 new wells will be drilled within the next 15 months and insisted there would not be any new LNG trains built unless additional gas is discovered.
Trinidad and Tobago has four LNG trains and last year was responsible for 67% of total US LNG imports.
While there was a reduction in the 3Ps, the survey reported a 5 tcf increase in what it says could yet be discovered.
Ryder Scott reported that Trinidad and Tobago has a potential for an additional 37 tcf of gas awaiting discovery.
The increase in the figure resulted from the collection and processing of 3D data by Canada Superior and Petro-Canada that showed there may be larger gas structures than originally thought in the blocks they are exploring.
Indonesia’s domestic gas needs remain top priority
Indonesian Vice-President Jusuf Kalla said his country will remain “consistent” in honoring current natural gas supply contracts with Japan, but that its top priority will be to meet domestic needs.
After meeting Aug. 20 with Japanese Prime Minister Shinzo Abe, who was on a state visit to Indonesia, Kalla said his country wanted to increase energy exports, including to Japan, as the country needs more export earnings.
To enable greater export potential, Kalla said improvements in the efficiency of domestic gas use will be made, while exploration will be expanded to increase the production of oil and gas. Kalla said exploration is already under way in Java, Papua, and the Natuna islands.
Meanwhile, according to Energy and Mineral Resources Minister Purnomo Yusgiantoro, there was no discussion between Abe and Kalla about any extensions of current LNG supply contracts with Japan.
For some time now, Indonesia has had rising domestic demand for gas. As a result, in June Indonesia said it was reallocating supplies of Tangguh LNG originally earmarked for Sempra Energy LNG in order to boost the amounts available to state-owned utility Perusahaan Listrik Negara (OGJ Online, June 18, 2007).
In March, in an effort to obtain higher prices for its LNG exported from Tangguh in Papua New Guinea, Indonesia said it wanted to renegotiate LNG contract terms with South Korea (OGJ Online, Mar. 6, 2007).
EPA: Current levels of refinery emissions acceptable
The US Environmental Protection Agency reported Aug. 23 that existing levels of toxic air pollutants released from US refineries do not require further controls to protect human health or the environment.
EPA recently conducted an analysis required under the Clean Air Act. The analysis examined potential risks that remain after implementation of maximum achievable control technology (MACT) standards.
MACT standards require industrial facilities to reduce emissions of toxic air pollutants. EPA first issued MACT standards for refineries in 1995.
Now EPA is seeking public comment on two options it proposed for controlling air emissions from refineries. The first option would require no additional emissions reductions because the risks are acceptably low. The second option would require additional emissions reductions for certain storage vessels and wastewater treatment units.
Under this alternative, EPA projects refineries could reduce air toxics emissions by as much as 4,600 tons/year from 153 facilities. EPA will accept public comment for 60 days following publication of the proposals in the Federal Register.
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Exploration & Development - Quick TakesStatoil finds gas with Midnattsol well off Norway
Statoil ASA made a deepwater natural gas discovery with its 6405/10-1 exploration well in the Midnattsol 281 production license in the Norwegian Sea. The find lies 40 km north of Ormen Lange field and 30 km south of the Ellida discovery. It is too early to declare the find commercial, Statoil said.
The company plans to drill an additional five exploration wells in the deepwater area in 2008. Three of these it will operate, said Frode Fasteland, acting head of exploration on the Norwegian continental shelf.
The Midnattsol well was drilled to a TD of 3,158 m subsea in 928 m of water by Transocean Inc.’s Transocean Leader semisubmersible. The well found gas in a late Cretaceous reservoir.
Core samples have been taken and an extremely thorough data acquisition program carried out, Statoil said. The collected data will be analyzed to delineate and define the discovery.
Midnattsol will be permanently plugged and abandoned. And the drilling rig will now be taken over by Eni SPA.
The licensees in PL 281, Blocks 6405/4, 7, and 10 are operator Statoil 50%, E.On Ruhrgas 20%, Petoro SA 20%, and CononoPhillips 10%.
Statoil’s interest in PL 281 was recently increased when it acquired Royal Dutch Shell PLC’s 20% interest (OGJ Online, Apr. 27, 2007).
Manning promises exploration incentives in 2008
Trinidad and Tobago Prime Minister Patrick Manning reported during his 2007-08 budget presentation that the Caribbean island nation next year will offer incentives to major oil and gas companies to explore for hydrocarbons in marginal fields.
Commenting on the recent Ryder Scott natural gas audit that showed Trinidad and Tobago’s production hitting a plateau in about 9 years, Manning said, “What is needed now is a new fiscal regime of incentives to stimulate further drilling in the Deep Marine areas of East Coast, marginal fields, heavy oil, and farm-in, farm-out arrangements.”
He added, “We confidently expect... new discoveries of oil and gas and the preservation of Trinidad and Tobago’s position as an industrial center in the region.”
During a recent energy conference in Port of Spain, the major oil and gas companies asked the Trinidad and Tobago government to review its taxation regime in high risk areas like its deepwater blocks.
Drilling & Production - Quick TakesIthaca to drill second Athena appraisal well
Ithaca Energy (UK) Ltd. entered into an agreement with Senergy Ltd. to use the Stena Spey semisubmersible and drilling management services to drill the second appraisal well on the Athena oil project in the Outer Moray Firth off Scotland.
Drilling which was scheduled to begin in late August, is part of a work program leading up to a field development plan expected to be filed in this year’s fourth quarter.
Well objectives are to evaluate the eastern lobe of the Athena discovery, for which probable undeveloped oil reserves have been independently verified at 28 million bbl (20 million bbl net to Ithaca).
Ithaca will spud the well close to the mapped northern pinch-out of the Cretaceous Upper Leek formation. The well site is midway between the 14/18b-11 well, which encountered good reservoir in the Upper Leek below the oil-water contact, and the 14/18b-12 well, which encountered tight reservoir in the Upper Leek sands but had an oil-leg in the Lower Leek sands (OGJ Online, Nov. 30, 2006).
Recent results of seismic processing following the drilling of the 14/18b-15 well have confirmed the selection of the bottomhole location for the planned well, which is designed to be kept as a production well and is in a position to optimally drain the eastern part of Athena field.
Ithaca had expected to drill this well with the Byford Dolphin semisubmersible this summer, but it has been delayed due to operational, scheduling, and weather-related issues on its current program (OGJ Online, Apr. 2, 2007).
Ithaca has decided to delay taking on the Byford Dolphin semisubmersible until later this year to allow the Stena Spey to begin the Athena work as soon as possible, the company said.
Williams studies Canadian oil sands expansion
Williams Cos., Tulsa, is making an engineering study for possible expansion of its Canadian facilities to extract ethane from off-gas emissions associated with its oil sands production in Alberta.
The company recovers and purifies natural gas liquids and olefins at its Fort McMurray and Redwater oil sands production facilities in Alberta that it has operated since 2002.
It is contemplating construction of a cryogenic processing plant, addition of a de-ethanizer, and expansion of its existing fractionator at its Redwater complex north of Edmonton, Alta; and addition of a de-ethanizer to the Redwater complex. The de-ethanizer could begin operating in stages as early as 2010; the new off-gas processing plant could start up in 2012, officials said.
“As the only company with facilities in service to recover olefins and natural gas liquids from the Canadian oil sands off-gas, Williams is uniquely positioned to provide these services,” said Randy Newcomer, vice-president. “Recovering rather than burning the liquids contained in the off-gas not only increases the value of the off-gas, but also results in a significant environmental benefit.”
Williams’s current operations at Fort McMurray and Redwater reduce emissions of carbon dioxide-a greenhouse gas-in Alberta by 219,000 tons/year. It also reduces annual emissions of sulfur dioxide-a contributor to acid rain-by more than 3,200 tons.
Williams’ contemplated expansion of its off-gas operations and ethane removal would further decrease emissions associated with oil sands production, officials said. The company recently signed nonbinding letters of intent specific to the expansions it will evaluate. It’s evaluation of ethane-recovery facilities is the subject of such an agreement with Nova Chemicals Corp.
Leed Petroleum secures rig for Gulf of Mexico work
Leed Petroleum PLC, a London-based oil and gas exploration and production company focused on the Gulf of Mexico, will begin a multiple well drilling program in September initially on its Eugene Island Blocks 183 and 184 in the gulf.
The company has signed a contract with Ensco Offshore Co. for use of Rig 98 to carry out the drilling. Leed is operator of Block 183 and the southern half of Block 184.
Processing - Quick TakesQatar Petroleum lets contract for refinery
State-owned Qatar Petroleum plans to build a grassroots refinery with 250,000 b/d capacity and other associated facilities in Messaieed, Qatar. QP has let a lump sum front-end engineering design contract to Technip for the work.
The $60 million contract covers the Al Shaheen facility and an oil pipeline that will extend from Al Shaheen oil and gas field 90 km offshore to Messaieed 110 km onshore, as well as other import-export facilities. Technip’s operations and engineering centers in Paris and Abu Dhabi will carry out the contract work.
The refinery, which will produce mainly gasoline, diesel, and jet fuel, will incorporate some of the most technologically advanced conversion units for upgrading bottom of the barrel products. The facilities are scheduled to be operational by yearend 2011.
Qatar currently has just one refinery at Umm Said. It has a capacity of 200,000 b/cd and is operated by National Oil Distribution Co.
Qatar’s crude production capacity is expected to increase to 1.1 million b/d by late 2008. The increase will come from expansion of Al-Shaheen oil field. A development effort in progress in Al Shaheen field will raise the field’s oil production to 525,000 b/d from 240,000 b/d (OGJ, Mar. 26, 2007, Newsletter).
BP won’t raise discharge limits at Whiting refinery
BP America Inc. on Aug. 23 promised to operate its 399,900 b/cd Whiting, Ind., refinery to meet the lower discharge limits specified in its previous wastewater treatment permit. BP’s pledge came after a new, recently approved permit, which allows for higher discharge limits, met with regional opposition.
“We will not make use of the higher discharge limits in our new permit,” said BP America Chairman and Pres. Bob Malone.
The new permit allows BP to increase discharge limits to 1,584 lb/day from 1,030 lb/day for ammonia and to 4,925 lb/day from 3,646 lb/day for total suspended solids. The permit is associated with a $3.8 billion upgrade project that would enable BP’s Whiting refinery to increase processing capacity for Canadian heavy crude to 90% from 30% and creates the capacity to increase production of clean fuels by 1.7 million gal/day.
Malone said if BP determines that the refinery cannot operate after the heavy crude project is implemented and still meet the lower discharge limits, the company will develop a project to allow it to do so.
He explained, however, that “if necessary changes to the project result in a material impact to project viability, we could be forced to cancel it.”
Malone said the project requires regulatory certainty. And “opposition to any increase in discharge permit limits for Lake Michigan creates an unacceptable level of business risk for this $3.8 billion investment,” he said.
During the next 18 months, BP will continue to seek issuance of other permits, continue project design, and explore options for operating within the lower discharge limits.
The company has agreed to participate with the Purdue Calumet Water Institute and the Argonne National Laboratory in a joint effort to identify and evaluate emerging technologies with the potential to improve wastewater treatment across the Great Lakes.
BP will provide a $5 million grant to Purdue University to help underwrite the research effort, Malone said.
Nigeria’s DPR assesses 26 refinery applications
Nigeria’s Department for Petroleum Resources (DPR) has received 26 applications from private companies wishing to build refineries in Nigeria.
According to DPR’s midyear 2007 report, four of the 26 companies had their licenses overturned in March because they failed to build the refinery by the given deadline. The applications are at different stages of processing.
Under DPR’s guidelines companies will be required to deposit $1 million for every 10,000 b/d of planned capacity, which would be refundable within 18 months provided the project is carried out to deadline.
The report also said the 210,000 b/d refinery in Port Harcourt operated at just about 38% capacity in the first half of this year. The facility is the only refinery working in Nigeria since Feb. 18, 2006. The Warri and Kaduna refineries remain closed because the Chanomi Creek pipeline, which would otherwise transport oil to both of the facilities, had been damaged by vandals.
Transportation - Quick TakesGermany suffers oil supply shortfall from Russia
During August Germany has suffered a one-third shortfall in oil supplies from Russia via the Druzhba oil pipeline network. The line delivers oil from Russia through Belarus en route to Europe.
Transneft Vice-Pres. Sergei Grigoryev told Interfax that OAO Lukoil and other smaller companies had allegedly cut deliveries and had not given a reason for doing so.
The 220,000 b/d PCK refinery at Schwedt in eastern Germany has sought other sources to make up for the shortfall of supply. The company said it had been informed by suppliers that there would be supply fluctuations and talks are ongoing between the parties.
Nevertheless the refinery is running at full capacity and is using its resources as well as oil supplies from the North Sea.
One possible reason that Lukoil has cut crude shipments to Germany is because it wants to sell directly to the German markets instead of through the traders who it is currently in conflict with, according to media reports. Full supplies are expected to resume this month.
In recent weeks there was speculation that there were problems with the pipeline network, which was why supplies had fallen. This is the second time in the last 8 months that Germany has seen a shortfall (OGJ Online, Jan. 10, 2007).
Kinder Morgan Canada starts Anchor Loop expansion
Kinder Morgan Energy Partners LP unit Kinder Morgan Canada has started construction on the $443 million (Can.) Anchor Loop project-the second phase of the Trans Mountain pipeline system expansion. Kinder Morgan received Canadian regulatory approval for the loop project last year (OGJ Online, Oct. 30, 2006).
The expansion, which will increase Trans Mountain’s capacity to 300,000 b/d from 260,000 b/d, is expected to be completed in November 2008.
Trans Mountain transports oil and products from Edmonton, Alta., to marketing terminals and refineries in British Columbia and Washington state. Earlier this year Kinder Morgan Canada commissioned 11 new pump stations, which boosted capacity on Trans Mountain to 260,000 b/d from 225,000 b/d. The pipeline has been operating at capacity since then.
The project entails looping 158 km of the Trans Mountain system through rugged terrain in Jasper National Park and Mount Robson Provincial Park.
Kinder Morgan Canada also continues to have discussions with customers for the next expansion phase (TMX-2) of the Trans Mountain pipeline system.
Questar, Enterprise to build Rockies gas hub
Questar Pipeline Co., Salt Lake City, and an affiliate of Enterprise Products Partners LP, Houston, signed a memorandum of understanding to build a 2.5 bcfd natural gas pipeline hub in the Rocky Mountain area. Questar will construct and operate the 7-mile, 30-in. hub pipeline.
The White River Hub, a header system to be owned equally by the two companies, will connect Enterprise’s gas processing complex near Meeker, Colo., with as many as six interstate pipelines in the Piceance basin area, including Questar’s.
The pipeline, from Questar Pipeline’s Greasewood, Colo., facilities to the nearby Enterprise Meeker gas processing complex, would provide hub-related services for area gas producers, marketers, and buyers.
Other pipelines expected to connect to the White River Hub are the Rockies Express Pipeline, owned by Kinder Morgan, Sempra, and ConocoPhillips; Kinder Morgan’s TransColorado Gas Transmission Co.; El Paso’s Wyoming Interstate Co. and Colorado Interstate Gas Co.; and the Williams-owned Northwest Pipeline Corp. The system would allow shippers on these pipelines to access markets throughout the country.
As foundation shippers, Enterprise has committed to 1.5 bcfd of firm capacity on the pipeline and Questar to 0.5 bcfd. An open season will be held immediately for the remaining firm capacity.
Assuming receipt of regulatory approvals and a successful open season, the companies expect pipeline construction to start in mid-2008 and for gas transmission to begin in fall 2008.
Petroecuador, Flopec plan LPG terminal, pipeline
Ecuador’s state-owned Petroecuador has awarded Dutch trader Trafigura Beheer a 2-year contract to supply LPG while an onshore maritime terminal and 50,000-tonne storage facility is being built in Monteverde, Ecuador.
Petroecuador said Trafigura will supply about 1.6 million tonnes, with monthly deliveries starting in November when Trafigura’s current contract expires. Trafigura will need a 40,000-tonne storage vessel and two, 2,500-tonne vessels to transport the LPG to the Tres Bocas terminal in Guayas province.
The contract will help meet demand while Petroecuador and state hydrocarbons maritime transporter Flopec build the Monteverde LPG terminal and pipeline.
Under a 5-year contract, Flopec will build and operate the Monteverde terminal and storage facility, while Petroecuador will build and operate the 146-km, 10-in. La Libertad-Pascuales pipeline and a storage terminal in Pascuales.
The Monteverde terminal will have a capacity to receive vessels exceeding 40,000 dwt.
The Ecuadoran government said the project will reduce operating costs by more than $30 million/year and will provide increased LPG storage efficiency and safety.