General Interest — Quick Takes
Shell to buy East Resources for $4.7 billion
Another major oil and gas company has entered a multibillion-dollar deal to acquire interests in North American unconventional resources.
Royal Dutch Shell PLC agreed to acquire the business of privately owned East Resources Inc. for $4.7 billion in a deal that includes a major land position in the Marcellus shale play of the eastern US.
Shell will pay cash to acquire East Resources subsidiaries holding the interests from East Resources and its private equity investor, Kohlberg Kravis Roberts & Co.
Based in Warrendale, Pa., East Resources has one of the largest land positions in the Marcellus shale play with 650,000 highly contiguous acres, mostly in Pennsylvania and mostly operated with high average working interests. The company also holds more than 100,000 net acres in the Niobrara shale oil play in the Rocky Mountain region. The total land position covered by the deal is 1.05 million net acres. East Resources produces about 60 MMscfd of gas equivalent, mostly gas.
Other major oil companies that have made large deals to acquire North American unconventional resource interests include ExxonMobil Corp., with its announcement last December of a $41 billion all-stock acquisition of XTO Energy Inc., and Statoil AS, with the $3.38 billion joint venture it formed in 2008 with Chesapeake Energy Corp. in which it acquired 32.5% of Chesapeake's Marcellus shale interests.
The East Resources deal isn't Shell's first venture into unconventional oil and gas.
This year, the company has added 1.3 million acres in tight sands gas interests to which it attributes potential recovery of more than 16 tcf of gas equivalent.
It also has acquired about 250,000 net acres this year in the part of the Eagle Ford shale play of South Texas that is yielding hydrocarbon liquids.
Shell also produces gas from tight sands in the Pinedale anticline in Wyoming and has tight-gas positions in South Texas, the Haynesville play of Texas and Louisiana, and western Canada.
Shell produced 810 MMcfd of gas equivalent from North American low-permeability reservoirs in 2009 at an operating cost below $2/Mcf.
Crescent, Rosneft sign cooperation pact
Crescent Petroleum of Sharjah and Rosneft Oil Co. of Russia have signed a strategic cooperation agreement covering oil and gas exploration and development in the Middle East and Africa.
The companies didn't specify projects they intend jointly to pursue.
In separate statements, both said: "Access to material and high quality new upstream projects will be facilitated by combining Rosneft's Russian petroleum industry experience, financial strength, and technical capabilities alongside Crescent Petroleum's extensive international operating experience and unique access within the Middle East and North Africa region."
Omar Ghobash, United Arab Emirates ambassador to Russia, said at a signing ceremony that the agreement followed 18 months of "high-level" contacts between the UAE and Russia.
Crescent is a private company that operates Mubarek oil and field off Sharjah through a subsidiary, Buttes Gas & Oil Co. International Inc. Mubarek, currently under redevelopment, has produced more than 100 million bbl of oil and condensate and 300 bscf of natural gas since start-up in 1974.
Crescent was a founder and owns about 21% of Dana Gas PJSC, Sharjah, and holds exploration and production interests in several countries, including Iraq.
Rosneft, 75% owned by the Russian government, holds reserves of 22.3 billion boe and in 2008 produced an average of 2.12 million b/d of oil, mostly in Russia. It also holds interests in Kazakhstan and Algeria.
FERC issues reporting rule for pipelines
The US Federal Energy Regulatory Commission issued a ruling on May 20 that is designed to make natural gas prices more transparent by requiring intrastate pipelines involved in interstate service to report transportation and storage transaction information more frequently and in more detail.
The rule, which is effective Apr. 1, 2011, requires intrastate pipelines operating under Section 311 of the 1978 Natural Gas Policy Act and Hinshaw pipelines operating under Section 1, Subsection C of the Natural Gas Act to provide more detailed information quarterly instead of semiannually or annually, FERC said.
FERC said the quarterly reporting requirement will help shippers make more informed purchasing decisions and improve the ability of both shippers and FERC to monitor actual transactions for evidence of market power or undue discrimination. FERC also is extending its cycle of periodic reviews of rates charged by these pipelines to 5 years from 3 years.
It noted that intrastate pipelines normally aren't subject to FERC jurisdiction so their operators will be encouraged to participate in the interstate pipeline network. Hinshaw pipelines also operate within a single state but may receive gas from outside the state without falling under the commission's NGA jurisdiction so long as all the gas is consumed within the state and regulated by a state commission, the federal regulator said.
The new rule replaces the Form 549 Intrastate Pipeline Annual Transportation Report with a new Form 549D on which pipelines will be required to report rates charged under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and shipper, according to FERC.
Exploration & Development — Quick Takes
Husky South China Sea appraisal well flows gas
Husky Energy Inc., Calgary, said the first appraisal well at its Liuhua 29-1 discovery on Block 29/26 in the South China Sea could be capable of delivering 60-70 MMcfd of gas.
The well, drilled to 2,930 m in 765 m of water, flowed at an equipment-restricted rate of 55 MMcfd from an undisclosed depth. More appraisal drilling, planned for later this year, is needed to improve understanding of the recoverable resource and provide reservoir data for a development plan, the company said.
Liuhua 29-1 field is Husky's third large deepwater gas discovery on the block. It is 43 km northeast of Liwan 3-1 field and 20 km northeast of Liuhua 34-2 field.
Husky expects to submit development plans for Liwan 3-1 and Liuhua 34-2 fields to regulatory authorities later this year. It will develop those two fields in parallel, starting production in 2013. It will submit a plan for Liuhua 29-1 when ready.
The West Hercules semisubmersible is preparing to spud the Liwan 5-2-1 exploration well on the block before returning to Liuhua 29-1 to drill a second appraisal well.
Llanos Carbonera oil find gauged in Colombia
Petrominerales Ltd., Bogota, said its Capybara-1 exploration well on Castor block in Colombia's Llanos basin pumped at the rate of 660 b/d of 29° gravity oil with 87% water cut from two intervals in Eocene Carbonera C7.
Petrominerales, a 66% owned subsidiary of Petrobank Energy & Resources Ltd., plans to place the well on long-term production test by the end of June.
The third well of the company's Central Llanos basin exploration program, Cerillo-1 on the Casanare Este block, reached 9,580 ft measured depth and was cased as a potential oil well based on indications of hydrocarbons while drilling. A completion rig is starting tests.
Logs at Mapana-1 on the Mapache block, the next well in the program, indicate 16 ft of net oil pay in Carbonera C7 and 9 ft in Guadalupe. TD is 8,220 ft.
After casing is set at Mapana-1, the drilling rig will move to Manzanillo-1, next prospect on the Mapache block.
On the Corcel block in the Llanos basin, the Corcel-C2 development is producing more than 3,000 b/d of 21° gravity oil at 20% water cut. The company plans to increase pump speed in the coming week.
The drilling rig is moving to Amarillo-1 and Baco-1, first two of an initial 10 exploration prospects to be drilled in the northeast part of the block. A second rig is to begin drilling the Boa-2 development well by mid-June.
Petrobras enters New Zealand with permit
Brazil's Petrobras International Braspetro BV has been awarded an exploration permit in the frontier Raukumara basin off the northeast corner of New Zealand's North Island.
It is Petrobras's first entry into the country and the first award of a permit in this region.
Permit PEP 52707 is valid for 5 years and covers an area of 12,333 sq km, which is nearly half the area within the entire Raukumara basin.
The basin lies at the northern end of the East Coast basin and is bound to the east by the East Cape Ridge and to the west by the Kermadec Ridge.
Water depths range from coastal to more than 2,400 m in the northern reaches.
New Zealand gazetted two blocks in the Raukumara basin in December 2008 and closed the offer at the end of January.
Petrobras submitted a bid that includes collection of seismic reflection data over both blocks. The subsequent permit award comprises all of Block 2 and a portion of Block 1.
The work program contains a number of options. The company has undertaken to acquire 3,000 km of 2D seismic data within 18 months and to interpret it within 24 months. It then has an option to surrender the permit.
If it continues Petrobras will acquire 800 sq km of 3D seismic within 36 months and interpret the data within 42 months. The company has a second option to surrender once the interpretation is completed.
If it chooses to enter the third phase, Petrobras will drill an exploration well within 60 months.
The company says it is targeting natural gas rather than oil and is looking for LNG-scale project finds.
The move into New Zealand is part of an Oceania strategy to broaden Petrobras's sources of LNG and comes on the heels of its farmin to 50% of MEO Australia's Carnarvon basin permit WA-360-P off Western Australia during April.
Drilling & Production — Quick Takes
Cobalt International invokes force majeure
Cobalt International Energy Inc. invoked a force majeure provision under its drilling contract with Diamond Offshore Co. for the Ocean Monarch drilling rig, which was moored and ready to drill on an exploratory well on Garden Banks Block 959 in the Gulf of Mexico.
Cobalt said it invoked the force majeure because of a May 27 announcement by the US government to temporarily suspend deepwater drilling in the gulf.
Already Cobalt had all necessary permits and insurance as required for drilling. The Houston independent also believes the direct financial impact of triggering force majeure on the Ocean Monarch will cost $15 million.
"Looking to the future, Cobalt believes that the action taken by the US government…will likely result in the delay of our Gulf of Mexico drilling program by approximately 6 months," the company said in a news release.
Other than this initial delay, Cobalt reaffirmed its intentions to execute all aspects of its entire gulf exploration and appraisal program as previously announced. Cobalt also focuses on offshore Angola and Gabon.
Husky starts N. Amethyst oil production
Husky Energy Inc., Calgary, said oil production started from North Amethyst field offshore Newfoundland and Labrador on May 31.
North Amethyst is the first satellite field development at Husky's White Rose project and was brought on production less than 4 years after discovery. It is also the first subsea tieback project in Canada, according to Husky.
The field is about 350 km off Newfoundland and Labrador and is the first step in the staged development of the White Rose satellite fields. Husky estimates that, as of Dec. 31, 2009, North Amethyst holds about 90 million bbl of reserves (34.7 million proved, 35.3 million probable, and 20 million possible).
Subsea wells in the North Amethyst drill center will tieback 6 km through flexible underwater flowlines to the SeaRose floating production, storage, and offloading vessel that processes production from White Rose.
Husky expects oil production from North Amethyst to peak at about 37,000 b/d after it drills and brings on line the remaining wells.
Husky operates White Rose and the satellite fields, holding a 72.5% working interest in White Rose field and a 68.9% interest in the satellites, which include North Amethyst and West White Rose.
Suncor Energy Inc. holds a 27.5% interest in the core White Rose field, and 26.1% interest in the satellite fields. The government of Newfoundland and Labrador, through Nalcor Energy—Oil & Gas, holds a 5% interest in the satellite fields.
Husky also will continue to examine the potential of other near-field tieback opportunities, including an assessment of the Hibernia reservoir sandstones beneath the main White Rose and North Amethyst fields.
BP to start production of Oman tight gas
BP PLC will begin production from two tight gas fields in Oman later this year, according to a senior Omani energy official.
"BP will start producing gas from Khazzan and Makarem fields in August," said Nasser al-Jashmi, the undersecretary of Oman's oil and gas ministry.
BP signed a production-sharing agreement with Oman in 2007 for the two gas fields, which lie on Block 61.
Jashmi said he expected production to reach less than 1 million cu m from the early production this year, but he said that the volume is expected to increase in 2011.
In November 2009, BP completed drilling five of eight appraisal wells as part of its development program for the reserves on Block 61.
"BP will drill eight appraisal wells in total by 2011," according to BP Oman general manager Jonathan Evans, who added, "So far we've done five wells, which have provided a lot of useful information on the nature and the scale of the reservoirs."
In a company report, Evans said, "Our latest test site, Khazzan 5, initially produced about 40 MMcfd of gas and has the highest flow rate of any well we've drilled so far."
According to analyst IHS Global Insight, the tight gas project on Block 61 has the potential to be a "game changer" for both Oman, alleviating its shortages fundamentally, and for BP, making it the first port of call for all with tight gas reserves globally.
In 2007, Oman's Oil and Gas Minister Muhammad bin Hamad al-Rumhi said BP would invest $700-750 million on the fields, which could contain as much as 30 tcf of gas, almost doubling the country's current reserves of 35 tcf.
Test finds shut-in time to prevent flow back
Saudi Aramco has developed a laboratory test for determining the downhole curing time needed for preventing resin-coated proppant flow back.
During hydraulic fracturing, the large volume of cold injection fluid decreases reservoir temperature, but the resin coating on the proppant requires a certain temperature to fuse the proppant particles together. To ensure the right temperature for curing the proppant, the well must be shut in to let the reservoir temperature increase.
Aramco said prior to its lab method, the industry did not have a way for determining this curing time.
To find the optimum curing time, its lab method uses sound to test the proppant properties under constant downhole pressure and increasing temperature.
The company notes that its field engineers have adopted the method and have successfully prevented losses due to proppant flow back.
On May 11, Aramco received US Patent 7,712,525 for "Determination of Well Shut-in Time for Curing Resin Coated Proppant Particles," developed by Hazim Abass, Mohamed Alqam, Mirajuddin Khan, and Abdulrahman Mulhem of the company's EXPEC Advanced Research Center.
Processing — Quick Takes
PBF to restart Delaware refinery in 2011
PBF Energy Co. LLC plans to restart the 190,000-b/d refinery at Delaware City, Del., formerly owned by Valero Energy Corp. in the first half of next year after performing "major maintenance work" (OGJ, Apr. 19, 2010, Newsletter).
PBF subsidiaries Delaware City Refining Co. LLC and Delaware Pipeline Co. LLC have completed their purchase of the refinery and associated pipeline and terminal for $220 million. Valero shut the facility in 2009, maintaining only terminal operations, which PBF said would continue.
PBF is an investment vehicle of Petroplus Holdings AG, Zug, Switzerland.
Valero said it continues to explore "strategic options" for its 166,000-b/d refinery at Paulsboro, NJ, and 235,000-b/d refinery in Aruba.
Iraq eyes grassroots refinery at Nassiriya
The Iraqi Ministry of Oil has advanced longstanding plans to build a world-scale refinery at Nassiriya in southern Iraq.
It has let a contract to Foster Wheeler AG for a feasibility study and front-end engineering design of a refinery with capacity of 300,000 b/d.
Plans for a refinery of that scale have been part of the ministry's rehabilitation of a refining industry ravaged since the 1980s by wars and limited investment.
At the Middle East Petroleum and Gas Conference in Bahrain in 2004, Iraqi officials discussed long-term plans for a 250,000-300,000-b/d grassroots refinery oriented to gasoline production (OGJ, May 17, 2004, p. 31).
Contract let for Cameroon refinery upgrade
Cameroon's Ste. Nationale de Raffinage (Sonara) has let an engineering, procurement, and construction management contract to Foster Wheeler AG for the first phase of a project to upgrade and modernize its 37,000-b/d hydroskimming Limbe refinery.
The project includes revamp of the crude distillation unit, addition of a vacuum distillation unit, a new catalytic reformer, and power-generation and related facilities.
Foster Wheeler handled front-end engineering and design.
Earlier, Sonara let a contract to Cegelec of France for upgrade of the refinery's control system (OGJ Online, May 20, 2010).
Transportation — Quick Takes
Enterprise books Haynesville Extension
Enterprise Products Partners LP and Duncan Energy Partners LP announced June 1 that Acadian Gas LLC had entered into an additional long-term contract with a shipper to transport natural gas on Acadian's Haynesville Extension pipeline, now under construction, increasing total capacity commitments by 200 MMcfd. Enterprise said it expects to "quickly" have the line fully contracted.
The Haynesville Extension is an expansion of the Acadian Gas intrastate natural gas pipeline system providing producers developing the Haynesville shale access to 150 end-use customers, including industrial and municipal consumers, on the Acadian system and markets across the eastern US through interconnects with 12 interstate pipelines, including the Florida Gas Transmission and Southern Natural Gas systems. Enterprise expects completion of the 270-mile Haynesville Extension at a capacity of 2 bcfd in third-quarter 2011 (OGJ Online, Oct. 28, 2009).
Acadian Gas LLC is 66% owned by Duncan Energy and 34% owned by Enterprise. Affiliates of Enterprise own the general partner of Duncan Energy and roughly 58% of the outstanding common units of Duncan Energy.
Enterprise also announced the expansion of its recently acquired State Line gas gathering system serving producers in the Haynesville shale area of Northwest Louisiana is scheduled for completion during June. The expansion of the State Line system, acquired from M2 Midstream LLC in April (OGJ Online, Apr. 1, 2010), will increase capacity to about 700 MMcfd from roughly 400 MMcfd. State Line includes the 180 MMcfd Battlefield gas treatment facility in southern DeSoto Parish, La.
State Line's expansion includes a new 250 MMcfd pipeline delivering gas from the Battlefield treating facility to the 42-in. OD Gulf South Pipeline at Kingston Station in DeSoto. Volume growth and demand for treating services have prompted Enterprise to expand its Battlefield and Keatchie treating facilities to add two amine units, each with a circulation rate of 700 gpm, the company said. The units will add up to 350 MMcfd of incremental treating capacity to the system, allowing producers in the region to bring newly drilled wells online, according to Enterprise. Enterprise expects these expansions to be completed in this year's fourth quarter.
Alyeska pipeline shut down after crude spill
A power failure prompted the May 25 shutdown of Alyeska Pipeline Service Co.'s Trans-Alaska Pipeline System. During scheduled testing of the fire command system at Pump Station 9, the station experienced a power failure, resulting in tank relief valves opening as designed. Tank 190 subsequently overflowed and oil was released to secondary containment surrounding the tank and lined with what Alyeska describes as an impermeable barrier.
The incident occurred as Alyeska was conducting fire command and valve leak testing at the station near Delta Junction during a planned 6-hr shutdown. The were no injuries and Alyeska evacuated personnel. The shutdown caused ANS producers to be prorated to 16%. Alyeska estimates up to several thousand barrels spilled into the 104,500-bbl capacity containment area.
Inpex confirms delay at Ichthys LNG project
Inpex Australia, Perth, reported a delay in its proposed Ichthys LNG project in Darwin. Inpex Pres. Naoki Kuroda said a final investment decision was now not expected until fourth-quarter 2011. This will mean production from the project will not begin until the last quarter of 2016.
Kuroda said the Ichthys project, which will produce gas from the field in the Browse basin off northwest Western Australia and pipe it more than 850 km to an LNG plant in Darwin, is very large and complex. Inpex is taking its time to optimize all aspects of the design to minimize the risk of increasing costs. In particular the company is focusing on reducing the weight of the offshore central processing facility and allowing more time to prepare and evaluate tender proposals.
This facility could be the world's largest floating processing platform, capable of stripping out 100,000 b/d of condensate. The project is expected to have an initial output of 8.4 million tpy of LNG from two trains. It will also produce 1.6 million tpy of LPG.
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