General InterestQuick Takes

EU, industry meet to discuss offshore practices

European Union Energy Commissioner Gunther Oettinger met with oil and gas executives to discuss EU legislation and industry best practices to prevent or respond to a disaster in European waters like the recent Macondo blowout in the Gulf of Mexico.

Little was divulged about what was discussed in that meeting. Oettinger later said there was a "general need and interest in initiating a dialogue on the subject of safety of operations."

Each company was asked to nominate a high-level representative as its contact with the commission in a major emergency. A list of questions was presented to the companies, and a follow-up meeting is planned to analyze their written responses and assess the need for further action.

Contents of the questionnaire were not made public, but Oettinger's press officer told OGJ one "could imagine which questions were asked—each company's risk management and its technical options in case of accident."

When the cause of the Macondo blowout is known, Oettinger said, the EU will be able to "determine whether any specific targeted measures need to be taken."

Meanwhile, the commission will review existing legislation applicable to such emergencies and will establish a closer relationship with national energy regulators.

Eurogas sees larger role for natural gas

Any future outlook for sustainable energy must involve a larger role for natural gas, said members of the European Union of the Natural Gas Industry (Eurogas) after its forecasting task force recently updated its 2007 assessment.

Current expectations of long-term development of gas demand are 15-20% lower than 3 years ago. Nevertheless, indications are natural gas consumption in EU member states will rise to 500-535 million tons of oil equivalent (toe) in 2030 from 437 million toe in 2007.

The share of gas in Europe's primary energy demand could rise by 2030 to 26.7% in the base case and 28.7% in the environmental scenario from a 24% share in 2007.

Demand primarily will be stimulated by electric power generation that should account for 36-38% of total gas demand by 2030, up from 30% in 2007, due to its "considerable potential" for reducing carbon dioxide emissions at low cost. But gas utilization in homes and businesses will play a role as will natural gas vehicles, and others.

The problem will be to secure gas supplies to meet future demand, as indigenous production in Europe (including Norway) will decrease from 250 million toe in 2007 to 200 million toe in 2020 and 145 million toe in 2030 when the EU gas market will need to import 70% of its supply from outside its borders. Even intra-EU unconventional gas production would not exceed 20-25 million toe/year.

Pointing out the procurement challenge must be considered within future global competition for gas, Eurogas strongly advocates the industry fosters long-term relationships with major suppliers, transit countries as well as multilateral organizations and structures.

CNPC buys 35% interest in Syria Shell

China National Petroleum Corp. has acquired a 35% interest in Syria Shell Petroleum Development, previously 100% owned by Royal Dutch Shell PLC.

Syria Shell holds interests in the Deir-Ez-Zor, Fourth Annex, and Ash Sham production licenses, which are operated by Al Furat Petroleum Co. Shell has a 31.25% interest in Al Furat.

The licenses cover 40 oil fields from which Shell's share of production last year was 23,000 b/d of oil.

Before the transaction, CNPC held interests in the production licenses and in Al Furat through its 50% ownership of Himalaya Energy Syria BV.

Paramount to acquire Redcliffe Exploration

Paramount Resources Ltd. has agreed to acquire Redcliffe Exploration Inc. in a purchase that values the smaller company at $68.5 million (Can.). Both companies are based in Calgary.

Paramount, which already owns 18% of Redcliffe's shares, will acquire the remaining 82% for 42¢/share.

The transaction is expected to solidify Paramount's Peace River Arch lands targeting the Montney and Nikanassin formations at Karr-Gold Creek, and it will add to Paramount's inventory of high quality liquids-rich gas prospects.

Under the agreement, Paramount will acquire about 115,000 (65,000 net) acres of undeveloped land, valued at $30 million (Can.) by Paramount, of which 48,000 (24,000 net) acres is in proximity to Paramount's Karr-Gold Creek project. Paramount also will acquire 850 boe of production proved and probable reserves of 3.35 million boe consisting of 2.05 million boe of gas and 1.30 million bbl of oil and NGLs, at Dec. 31, 2009.

Paramount has now consolidated 99,000 (74,000 net) acres of land at Karr-Gold Creek, providing an inventory of more than 200 drilling locations in both sour and sweet, liquids-rich tight gas reservoirs.

As part of the agreement, expected to close at the end of June, Paramount also will assume Redcliffe's $12.5 million (Can.) of net debt.

In March, Paramount announced plans to drill as many as eight operated oil wells in the Cameron Hills field area of Canada's Northwest Territories in 2010 (OGJ Online, Mar. 11, 2010).

In 2008, Redcliffe tested a Triassic Halfway sour oil and gas discovery at Wapiti in the Peace River arch area of west-central Alberta (OGJ Online, Mar. 17, 2008).

Industry Scoreboard

Exploration & DevelopmentQuick Takes

USGS: Nile Delta is big gas-liquids province

The Nile Delta contains an estimated 223 tcf of undiscovered, technically recoverable natural gas and 5.9 billion bbl of natural gas liquids, the US Geological Survey said May 18.

The province also contains a mean 1.7 billion bbl of oil, the survey said.

In April, USGS said the Levant basin, which borders the Nile Delta on the east, contains 122 tcf of gas and 1.7 billion bbl of oil (OGJ Online, Apr. 19, 2010).

"Taken together," USGS said, "the Nile basin and Levant basin assessments establish the eastern Mediterranean region as having world-class potential for undiscovered natural gas resources."

The recent assessment takes in the Nile Margin Reservoirs Assessment Unit, lying onshore and nearshore in northern Egypt with numerous discoveries, and in deeper water the Nile Cone Assessment Unit. USGS didn't assess the Mediterranean Ridge Assessment Unit, between Egypt and western Turkey, or the Eratosthenes Seamount Assessment Unit south of Cyprus.

The two assessed units contain more than 100 gas fields and three oil fields.

"By far, the largest resource is estimated to be in the Nile Cone AU, with a mean volume of 217 tcf and 5.7 billion bbl of NGL," USGS said. That area is in deeper water and less drilled than the Nile Margin Reservoirs AU.

Undiscovered, technically recoverable resources are those that have yet to be discovered, but if found, could be produced using currently available technology and industry practices.

By comparison, USGS estimated 643 tcf in Russia's West Siberian basin, 426 tcf in the Rub Al Khali basin, 227 tcf in the Greater Ghawar uplift, and 212 tcf in the Zagros Fold Belt.

The Nile Delta is larger than anything USGS has assessed in the US, where it estimated 85 tcf in the Southwestern Wyoming Province, 73 tcf in the National Petroleum Reserve-Alaska Province, and 70 tcf each in the Western Gulf Basin Province of Texas and Louisiana.

Shell, PetroChina sign Qatari E&P agreement

Royal Dutch Shell PLC and PetroChina Co. Ltd. have signed an exploration and production-sharing agreement (EPSA) covering pre-Khuff gas targets on Block D on and off Qatar.

The block covers 8,089 sq km near Ras Laffan.

The 30-year agreement has a 5-year initial exploration period, during which Shell and PetroChina will conduct exploration technical studies; shoot 2D and 3D seismic surveys; process, reprocess, and interpret seismic data; and drill an unspecified number of exploratory wells to strata older than Permian Khuff.

Part of supergiant North gas field, which produces from the Khuff formation, overlies Block D.

Shell is operator with a 75% equity share. Petrochina holds the remainder. Qatar Petroleum (QP) will supervise production that might result from the program and buy the gas.

QP signed a pre-Khuff EPSA covering 5,649-sq-km offshore Block BC with China National Offshore Oil Corp. last year.

"QP is also preparing for additional pre-Khuff reservoir exploration tenders in the near future," said Qatari Deputy Prime Minister and Minister of Energy and Industry Abdulla bin Hamad Al-Attiyah.

Statoil to develop gas find north of Mikkel

Norway's Statoil will develop a small but commercial natural gas discovery in the Norwegian Sea north of Mikkel field as a satellite to Asgard field.

The 6407/2-6 S exploration well discovered Flyndretind, a gas reservoir with a small oil column in the Tilje formation of Early Jurassic age, about 5 km north of Mikkel field and 200 km north of Kristiansund. Statoil's preliminary estimate of discovery size is 2-4 MM standard cu m of oil equivalent.

The Ocean Vanguard semisubmersible drilled the Flyndretind exploratory well to 3,166 m in 253 m of water. The licensees will consider various development solutions producing the discovery towards existing infrastructure at Asgard field, Statoil said.

The well is the first exploration well in Statoil-operated production License 473 awarded in 2007. Drilling is complete, and the well will be permanently plugged and abandoned.

Falklands indicated oil find suspended

Rockhopper Exploration PLC ran liner and suspended for later tests its 14/10-2 well on the Sea Lion prospect, saying it could be the first oil discovery in the North Falkland basin in the South Atlantic.

The company air-freighted rock and fluid samples to the UK for study after it TD'd the well at 2,744 m because the Ocean Guardian semisubmersible is not equipped to analyze them.

Rockhopper listed the following preliminary observations:

• All samples indicated to be oil.

• The sample chambers filled rapidly, indicating a good quality reservoir with no evidence of any free water as the sample chambers filled.

• Filling characteristics suggest a mobile crude oil.

Pressure data were good, with most attempted test points successfully located in good quality reservoir, the company said:

• Pressure readings indicate the possibility of two separate oil columns.

• No oil water contacts or water sands have been recognized in the well.

Rockhopper holds 100% interest in PL032 (see map, OGJ, May 17, 2010, p. 37).

Drilling & ProductionQuick Takes

Microseismic aids Horn River basin frac work

Apache Canada Ltd. adjusted hydraulic fracturing parameters in real time as the result of a microseismic survey in the Horn River basin in Northeast British Columbia.

Geophone strings were deployed in a variety of geometries in vertical and horizontal sections of two observation wells for more than 30 days to record microseismic events during more than 75 frac jobs in 13 nearby wells.

Apache used the data to experiment with how different perforation patterns affected fracture propagation and make real-time changes. At one point, for example, the data showed an absence of growing microseismic activity, alerting Apache to switch from pumping proppant to flushing a well with water to avoid a potentially costly sanding-off of the fractures.

Baker Hughes and VSFusion, a borehole seismic processing joint venture between Baker Hughes and CGGveritas, called the project one of the largest frac monitoring surveys ever undertaken. Data were displayed at the field site and in Apache's offices in Calgary in Houston.

Apache Canada said the ability to evaluate frac effectiveness during and after the project enabled it to optimize the spacing of horizontal wells on future drilling pads. It said the potential cost savings might exceed the survey cost.

Alberta starts negotiations for RIK bitumen

After reviewing submitted proposals, the government of Alberta said it will start negotiating for upgrading its royalty-in-kind bitumen with North West Upgrading Inc. (NWU). It expects to conclude the negotiations by yearend.

NWU has proposed to build a 150,000 b/d refinery in three stages northeast of Edmonton. The proposed project includes newer technologies and an integrated carbon capture and storage capability to reduce carbon dioxide emissions.

If negotiations are successful and the refinery is built, Alberta expects the refinery to process 75,000 b/d of RIK bitumen. Processing would include upgrading the bitumen to synthetic crude as well as to higher-value products such as diesel fuel.

Alberta Energy Minister Ron Liepert said, "This project has significant potential for Alberta to support the Provincial Energy Strategy goals of increased value-added production and clean energy production."

Canadian Natural Resources Ltd. had announced that it will finalize the acquisition of 50% of NWU by yearend (OGJ Online, Jan. 28, 2010).

Jacos seeks to expand oil sands operations

Japan Petroleum Exploration Co. subsidiary Japan Canada Oil Sands Ltd. (Jacos) submitted a joint application to the Alberta Energy Resources Conservation Board and Alberta Environment for approval to expand its oil sands production operations.

Jacos' application requests an expansion of its operations in the Hangingstone area leases of up to a maximum incremental production of 35,000 b/d of bitumen. Based on the planned development scenarios, Jacos said ongoing production from the expansion facilities could average 25,000-30,000 b/d.

Jacos also is commencing the preliminary engineering phase, during which the plant capacity and configuration will be optimized. Jacos said it has allowed 18 months for the regulatory approval and front-end engineering and design processes.

"In late 2011, the company anticipates project sanction, subject to obtaining regulatory approval, as well as the completion of the preliminary engineering along with updated project costs and economics," Jacos said.

Upon approval, construction of the central production facility is expected to begin in the winter of 2011-12 with initial site clearing and rough grading, Jacos said. Production startup is anticipated by the end of 2014.

In 2008, Japex said it planned to invest ¥240 billion over the next 5 years, of which ¥160 billion would be used to develop and explore projects outside of Japan, including in Libya, Indonesia, and Canada (OGJ Online, May 29, 2008).

Jacos is operator of the oil sands venture with a 75% working interest. Nexen Inc. holds the remaining 25%.

CNOOC group to develop Iraqi oil fields

CNOOC Ltd. and partners have signed a technical service contract with the Iraqi government to develop the Missan oil fields 350 km southeast of Baghdad.

The group committed to raise production to 450,000 b/d from about 100,000 b/d in 6 years, earning $2.30/bbl of incremental output beyond 10% above the current rate. The 20-year contract provides for cost recovery.

CNOOC is operator with 63.75% participating interest. Iraqi Drilling Co. holds 25%, and Turkish Petroleum Co. (TPAO) holds 11.75%. TPAO replaced Sinopec, which withdrew from the project.

Processing Quick Takes

Marathon to sell Minnesota refinery

Marathon Oil Corp. has signed a nonbinding letter of intent with a group of investment firms for the sale of its 74,000-b/d St. Paul Park, Minn., refinery and other downstream assets in Minnesota.

The sale would include a terminal, 166 SuperAmerica convenience stores, and the SuperMom's Bakery, SuperAmerica Franchising LLC, interests in Minnesota pipelines, and inventories.

Marathon said it expects the value of the transaction to exceed $800 million.

The buyers—ACON Investments LLC, NTR Partners LLC, and TPG Capital LP—have a period during which to work toward negotiation of definitive agreements. Marathon expects closing in the third or fourth quarter of 2010.

The refinery has 27,100 b/d of fluid catalytic cracking capacity and 18,500 b/d of semiregenerative catalytic reforming capacity.

Enterprise, Duncan to expand Eagle Ford plants

Enterprise Products Partners LP and Duncan Energy Partners LP plan to expand their jointly owned Shoup and Armstrong processing plants in South Texas. The plants process natural gas and fractionate NGLs.

The companies said the upgrades are part of a more comprehensive plan to expand their midstream infrastructure in South Texas to handle increasing natural gas production from the growing Eagle Ford shale play.

Work at Shoup, in Nueces County, Tex., will modify existing fractionation to increase capacity to 77,000 b/d with work completed in this year's second quarter. Incremental volumes of NGLs to fill the additional capacity will be supplied by six existing Enterprise gas plants currently feeding Shoup. Production from these plants will increase over the next 6 months as the quantity and quality of the gas supplies increase, said the announcement.

Modifications to existing infrastructure at the Armstrong plant in DeWitt County, Tex., will increase its fractionation capacity to more than 20,000 b/d. Supply for the increase will be enhanced by an efficiency improvement at the on site natural gas processing plant, said the announcement.

The improvements in processing capabilities, scheduled for completion in the fourth quarter, will increase NGL recoveries. In addition, the gas plant and fractionator upgrades will allow Armstrong to handle the more liquid-rich gas that characterizes much of the reserves in the Eagle Ford shale.

Elsewhere in the Eagle Ford shale, Enterprise continues work on two gas pipeline projects it expects to provide more than 200 MMcfd of incremental transportation capacity.

The final segment of pipeline that completes the White Kitchen lateral will be completed in mid-July. The 62-mile line runs through the heart of the Eagle Ford shale in LaSalle and Webb counties and connects two existing Enterprise 20-in. lines that lie at the northern and southern edges of the play.

Construction is also nearing completion on the first segment of the east-west Eagle Ford shale mainline project. The 34-mile, 24-in. line will connect the companies' South Texas pipeline in southwest LaSalle County to the White Kitchen lateral by June.

Transportation Quick Takes

WBI to expand Bakken pipeline capacity

Williston Basin Interstate Pipeline Co., the wholly owned natural gas transmission pipeline subsidiary of MDU Resources Group Inc., announced plans May 19 to expand its existing gas pipeline capacity by about 33% in the Bakken production area in northwestern North Dakota.

The proposed expansion would add up to 30 MMcfd to existing volumes from the Bakken production area for delivery to Northern Border Pipeline. The expansion project will consist of adding facilities to an existing compressor station in northwestern North Dakota. WBI expects the expansion to enter service in November 2011.

WBI's existing gas pipeline system extends throughout the Bakken production area in western North Dakota and eastern Montana. WBI completed an expansion of its pipeline system in 2008 and transports roughly 90 MMcfd of gas from 11 Bakken production area receipt points. In addition to the expansion project, WBI is working with gas producers and processors to add gas receipt points to its system throughout the Bakken production area.

An open season for the Bakken Expansion Project will run through June 2.

Oneok Partners LP in April announced plans for construction of the 100 MMcfd Garden Creek gas processing plant in eastern McKenzie County, ND, and related expansions for completion in fourth-quarter 2011. In addition to the plant, Oneok's gas gathering and processing segment will invest $200-205 million during 2010-11 for new well connections, expansions, and upgrades to existing gas gathering in the Bakken shale (OGJ Online, Apr. 22, 2010).

Santos lets contract for CSG-LNG project

Santos Ltd., Adelaide, has let a contract to Fluor Australia for the engineering, procurement, and construction phase of the upstream facilities for its planned coal seam gas-LNG project in Queensland.

Santos also extended Fluor's engineering design contract to include $50 million (Aus.) worth of early works activities. The company expects to award formally the EPC contract when it makes its final investment decision on the project.

The scope of work comprises all CSG and associated water-gathering and processing infrastructure for the Fairview and Roma fields in the Surat-Bowen basins.

Santos officials said a final investment decision for the project would be delayed at least 6 months while Santos and its JV partner Petronas evaluate the implications of the federal government's planned 40% resource rent tax on the mining industry (OGJ Online, May 11, 2010). However, Santos said the development remains on track to deliver its first cargo of LNG in 2014.

The project consists of a one-train, 3.6 million tonne/year LNG plant, plus associated field infrastructure, and a pipeline to feed CSG to Gladstone. Santos has 60%. Petronas has 40% and will purchase 2 million tpy of LNG from the Gladstone plant.

LNG Ltd. lets contract for Fisherman's Landing

Liquefied Natural Gas Ltd. has announced a fixed-price engineering, procurement and construction cost for its proposed Fisherman's Landing LNG plant in Gladstone of $720 million. Subsequent trains would cost $300 million each.

The trains will have a nameplate capacity of 1.85 million tonnes/year of LNG with work expected to take 30 months. LNG Ltd. said capital cost for the marine works, including ship-loading structures, dredging, and reclamation will be $85 million.

LNG Ltd.'s proposed contractors are SK Engineering & Construction and Laing O'Rourke Australia Construction.

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