GENERAL INTEREST — Quick Takes
Hess files documents for retail spinoff
Hess Corp. has filed documents with the US Securities and Exchange Commission for the spinoff to shareholders of its retail business, which includes 1,350 gasoline-convenience stores bearing the company's brand in 16 states along the US East Coast.
Hess has been exiting downstream businesses to concentrate on international exploration and production (OGJ Online, Nov. 1, 2013).
Hess undertook many large-scale divestitures in 2013, notably selling its Indonesian assets to OAO Lukoil for $1.3 billion, Russian subsidiary Samara-Nafta to OAO Lukoil for a $2.05 billion, and energy marketing business to Centrica PLC subsidiary Direct Energy for $1.2 billion (OGJ Online, Dec. 2, 2013).
EPL to ramp up oil production in 2014
EPL Oil & Gas Inc. intends to spend $360 million on oil-dominated, lower-risk development activities in 2014, focusing on the exploitation of the shallow sections within EPL's Ship Shoal, West Delta, South Timbalier, and Main Pass core field areas.
The company expects its capital spending to be front-loaded to drive production growth and organic reserve replacement.
"This front-loaded plan should deliver oil production for 2014 above our organic growth target of a minimum of 10%/year, while providing us the flexibility to modify the spend up or down depending upon market conditions," said Gary Hanna, EPL president and chief executive officer.
"It is also important to keep in mind that this initial budget of $360 million is in addition to our recently announced $70 million acquisition within the prolific Eugene Island 258/259 field," Hanna added.
The company plans the continuation of an active drilling program from fourth-quarter 2013, as there are 5 rigs working within the company's core field areas. It intends to ramp up to 8 rigs working in 2014, primarily consisting of jack up and hydraulic workover units.
Drill wells and sidetrack operation will comprise 70% of EPL's capital budget. The remaining 30% will be divided to 17% on major rig workovers and waterflood opportunities intended to drive oil production increases for select reservoirs within core field areas, and 13% for facility projects.
EPL said its midpoint oil guidance in 2014 is expected at 19,500 b/d, with the ability to grow to 20,500 b/d, 6% higher than 2013.
Natural gas is expected to be flat compared with 2013 at 30 MMcfd at the midpoint of guidance. Total company production is expected to range from 23,000-26,000 boe/d.
The company also intends to spend $50 million on plugging and abandonment and other decommissioning activities.
BLM issues draft EIS for Monument Butte project
The US Bureau of Land Management issued a draft environmental impact statement for Newfield Exploration Co.'s proposal to drill as many as 5,750 oil and gas wells over 16 years in an existing oil and gas producing area in Utah's Duchesne and Uintah counties.
Newfield's proposed Monument Butte Project encompasses nearly 120,000 acres south of Myton, Utah, and would result in about 170 miles of roads accompanied by a similar amount of pipelines and additional infrastructure, BLM's Vernal field office said late last month. Some 16,129 acres would be disturbed, it noted.
The proposed activity would be in the southern portion of the Greater Monument Butte field, which the Houston independent acquired in 1994 and is its largest Rocky Mountain asset, according to Newfield's web site.
The field is the largest federal unit in the Lower 48 US states and produces oil primarily from the shallow Green River formation, it noted.
BLM has scheduled public hearings on the draft EIS Jan. 22 in Salt Lake City, Jan. 22 in Roosevelt, and Jan. 23 in Vernal, the US Department of the Interior agency's notice said. Comments will be accepted through Feb. 4, it indicated.
Exploration & Development — Quick Takes
Statoil makes Askja oil, gas discoveries
Statoil ASA and PL272 partners have made a gas find in the Askja West prospect and an oil find in the Askja East prospect in the North Sea.
The exploration wells 30/11-9 S and 30/11-9 A are between the Oseberg and Frigg fields, 13 km southeast of the Statoil-operated Krafla-Krafla West discoveries that will be developed alongside Askja.
Main wellbore 30/11-9 S tested the Askja West prospect and proved a net gas column of 90 m in late and middle Jurassic rocks. Sidetrack 30/11-9 A tested the Askja East prospect and proved a net oil column of 40 m in the same geological formations. The reservoir properties were as expected in both wells.
Statoil estimates total volumes of 19-44 million boe in Askja West and Askja East.
"This demonstrates once again that even the most mature parts of the NCS still have an exciting value creation potential," stated May-Liss Hauknes, Statoil's vice-president, exploration, North Sea. "We are convinced that there are still attractive opportunities both in near-field exploration and in more material growth plays," she said.
The wells are the second and third exploration wells in production license 272 awarded in the 2001 North Sea Awards (NST2001) in 2002. Both wells were drilled by the Ocean Vanguard, which will now move to production license 628 in the North Sea to drill Statoil-operated well 25/9-4.
Lundin spuds appraisal well on Johan Sverdrup find
Lundin Petroleum AB, through its wholly owned subsidiary Lundin Norway AS, reported that drilling has started of appraisal well 16/3-8S on the Johan Sverdrup discovery in the North Sea sector of the Norwegian Continental Shelf.
The well is on PL501 at the crest of the Avaldsnes High in the eastern part of the discovery with the objectives to establish the depth, quality, and thickness of Zechstein group carbonates of Permian age and investigate the presence and quality of Jurassic reservoir sequences about 3.9 km southeast of the 16/2-6 discovery well.
Well 16/3-8S is expected to provide information of the Zechstein group carbonates subcropping the Jurassic reservoir in the Avaldsnes High area of the Johan Sverdrup discovery, Lundin said. "The carbonates may play an important role for the development of this part of the discovery both as a potential good oil reservoir and to optimize the production planning of the Jurassic oil reservoir directly on top of it," the company noted.
Planned total depth for the well is 2,025 m below mean sea level, and it will be drilled using the Bredford Dolphin semisubmersible drilling rig. Drilling is expected to take 45 days.
EPL to buy oil, gas assets in central Gulf of Mexico
EPL Oil & Gas Inc. signed a purchase and sale agreement with Nexen Petroleum Offshore USA Inc. for oil and gas assets in the shallow-water central Gulf of Mexico for $70.4 million.
The Eugene Island 258/259 field is comprised of 100% working interest in each of leases 254, 255, 257, 258, and 259. The assets are producing 900 net boe/d, 95% of which is oil, and proved reserves as of the Sept. 1, 2013, effective date are 2.6 million boe, 91% of which is oil.
EPL said the field areas show shallow decline and the company has identified upside potential beyond the current proved reserves.
Gary Hanna, EPL's president and chief executive officer, noted, "This purchase dovetails nicely into our commitment to acquire new 3D datasets. A new Full Azimuth Nodal dataset is currently being shot covering these field areas, and we expect to have the data in house during the second half of 2014."
EPL in 2007 reported dual oil and gas successes in the South Timbalier and Eugene areas of the gulf shelf (OGJ Online, Aug. 6, 2007).
Drilling & Production — Quick Takes
Petrobras reports start-up of Roncador's P-55 platform
Petroleo Brasileiro SA (Petrobras) reported its semisubmersible P-55 platform in Roncador field in Campos basin offshore Brazil.
The platform is one of the company's strategic projects in its 2013-17 business and management plan. Part of Roncador's field Module 3 project, it will be connected to 17 wells, 11 of which encompass oil and gas production while 6 cover water injection. The platform will rest in 1,800 m of water and is designed to process 180,000 b/d of oil, compress 6 MMcfd of natural gas, and inject 290,000 b/d of water.
Petrobras said P-55 is the biggest semisubmersible platform ever built in Brazil and one of the biggest of its kind worldwide, weighing 52,000 tons and with an area of 10,000 cu m.
The new unit will operate along with platforms P-52 and P-54 (OGJ Online, Nov. 26, 2007; OGJ, Feb. 4, 2008, p. 41), already installed in Roncador field, and with platform P-62, which has departed the Atlantico Sul shipyard in Ipojuca (Pernambuco state) for Module IV of the field.
Petrobras in 2008 canceled orders for the construction of the P-55 platform along with the P-57 floating production, storage, and offloading unit, citing excessive cost (OGJ Online, Feb. 18, 2008).
Petrobras lets two contracts for ultradeepwater fields
Petroleo Brasileiro SA has let two ultradeepwater contracts to Technip for the supply of flexible pipes for the Sapinhoa Norte field and I5 at Lula field (formerly Tupi) in the Santos basin presalt area offshore Brazil. The fields lie in as much as 2,500 m of water. The value of either contract was not disclosed.
The combination of both contracts covers the supply of 100 km of flexible pipes for oil production, gas lift, and gas injection, Technip reported. It also includes related equipment for the presalt area, to be installed on the Cidade de Angra dos Reis and Cidade de Ilhabela floating production, storage, and offloading units.
BPZ starts well offshore Peru at 2,100 b/d
BPZ Energy, Houston, has started production from a development well on Albacora oil field offshore Peru at an early rate of 2,100 b/d of oil gross and spudded another well nearby.
The new producing well, Albacora A-18D, flowed naturally, with a 11% water cut, from perforations in three intervals totaling about 130 ft.
BPZ spudded the Albacora A-19D development well targeting a structural position similar to that of the A-18D well, aiming for total measured depth of 12,500 ft. Water depth at Albacora, which produces via a fixed platform in the northern part of Block Z-1, is less than 200 ft.
On Corvina oil field, south of Albacora on the same block, BPZ recently sidetracked the CX15-2D well after drill pipe became stuck in the original hole and was redrilling the last 2,300-ft section (OGJ Online, Jan. 19, 2011). It reported oil shows in the targeted section and expected to complete the well in late January.
During tests, the CX15-1D development well on Corvina field produced an average of 440 b/d of oil from one interval with a water cut of 8%. Two of four intervals in that well remained to be tested at the time of the report.
BPZ has two platforms on Corvina field. Gross production from Block Z-1 recently has risen to 4,900 b/d of oil, 53% from Albacora and the rest from Corvina. The block's production in the fourth quarter of 2013 averaged 2,725 b/d, which included test output from the CX15-1D and Albacora A-18D wells.
BPZ holds a 51% working interest in Block Z-1, which it is developing in partnership with Pacific Rubiales Energy Corp.
On onshore Block XXIII, BPZ on Jan. 5 spudded the Caracol 1X exploration well with a target depth of 3,500 ft. The main objectives are the Oligocene Heath and Mancora formations. BPZ plans two more exploration wells on the block, in which it has a 100% working interest.
The company also plans exploratory drilling in what the company describes as "conventional and nonconventional oil plays" on onshore Block XXII later this year.
Nexen lets EPC contract for North Sea offshore assets
Nexen Petroleum UK Ltd., a wholly owned subsidiary of CNOOC Ltd., has let an engineering, procurement, and construction contract to AMEC PLC for Nexen's North Sea offshore assets.
The deal encompasses operational modifications and brownfield projects, and is reimbursable for 6 years, with the option of two extensions for an additional 2 years each.
AMEC in 2005 was responsible for the hook-up and commissioning support of Nexen's Buzzard oil and gas production platform.
Nexen in 2004 acquired EnCana (UK) Ltd., an EnCana Corp. UK subsidiary, for $2.1 billion, providing Nexen with interests in the Buzzard oil and gas discovery, along with Scott and Telford fields plus other satellite discoveries, and interests in exploratory blocks totaling 740,000 net undeveloped acres (OGJ Online, Nov. 3, 2004).
PROCESSING — Quick Takes
ExxonMobil wraps Singapore plant expansion
ExxonMobil Corp. has completed and commissioned the multibillion dollar expansion of its chemical complex in Jurgong Island, Singapore. The expansion project more than doubles the size of the plant's finished product capacity, making it the largest chemical expansion in ExxonMobil's history as well as positioning it to meet rapidly growing global chemical demand, two thirds of which will come from Asia-Pacific.
In addition to one of the world's largest ethylene steam crackers, the expansion includes two polyethylene plants, a polypropylene plant, a metallocene elastomers unit, an oxo-alcohol unit, and an aromatics expansion (OGJ Online, May 30, 2013; Dec. 28, 2012).
Also included in the expansion is a steam cracker capable of processing a wide range of feedstock—from light gases to crude oil—to produce an expanded slate of premium and commodity petrochemicals, ExxonMobil said.
The Singapore chemical complex, which now accounts for about one quarter of ExxonMobil's global chemical capacity, came on stream in 2001 and is integrated with ExxonMobil's 605,000-b/d Singapore refinery (OGJ Online, July 3, 2001).
Contract let for new Turkish refinery
Star Refinery AS, Istanbul, has let a service-related contract to a subsidiary of Foster Wheeler for the grassroots Aegean refinery to be built within the Petkim Petrokimya AS (Petkim) complex at Aliaga, Turkey.
The contract is for project management consultancy services, Foster Wheeler said. The value of the contract was not disclosed.
The refinery is designed to process a range of different crudes, including Urals, Azeri Light, and Kirkuk, to produce a range of products including jet fuel, diesel, naphtha, petroleum coke, and LPGs, according to Foster Wheeler.
Commissioning of the refinery is slated for 2017.
Foster Wheeler executed the front-end engineering design for the entire refinery and also provided the license and basic design package for the delayed coker, which will use Foster Wheeler's SYDEC delayed coking technology.
Star Refinery is the first project planned on the Petkim Peninsula by SOCAR Turkey Energy AS, a joint venture of State Oil Co. of Azerbaijan Republic and the Turkish government. SOCAR Turkey owns 51% of Petkim, operator of a petrochemical complex with which the new refinery will be integrated (OGJ Online, Dec. 6, 2013).
The refinery will have a 66,000-b/d hydrocracker, a 40,000-b/d delayed coker, and a 28,000-b/d continuous catalytic regeneration reformer.
Hydrotreating capacities will be 20,000 b/d for naphtha, 26,000 b/d for kerosine, and 68,000 b/d for diesel. The refinery also will have a 3.84-million cu m/day hydrogen unit.
Pennant's Hickory Bend plant ready for operations
Pennant Midstream announced that its 200-MMcfd Hickory Bend cryogenic natural gas processing plant in the Utica shale at New Middletown, Ohio, is ready to begin operations. The plant's gathering system includes about 55 miles of 20- and 24-in. OD wet gas gathering pipelines. These pipelines will support delivery of more than 600 MMcfd, allowing for expansion if demand warrants, and Pennant is preparing sites for two additional plants at Hickory Bend.
Dry gas from the plant will go to homes and businesses across Appalachia, and the NGLs will be shipped through a 12-in. OD, 38-mile pipeline and existing infrastructure to Utica East Ohio's Harrison County, Ohio, fractionator (OGJ Online, Sept. 30, 2013). Hickory Bend will support rich-gas production from Hilcorp Energy Co. and other producers in the area.
NiSource Midstream Services LLC operates Pennant, which is jointly owned by Harvest Pipeline (an affiliate of Hilcorp) and NiSource. The initial 200-MMcfd plant cost $375 million.
Keyera expanding Fort Saskatchewan NGL fractionation
Keyera Corp. is expanding its NGL fractionation and storage site in Fort Saskatchewan (KFS), more than doubling C3+ capacity to 65,000 b/d from 30,000 b/d. The project will also include new product receipt facilities, operational storage, and pipeline interconnections. Detailed engineering work is under way, with Keyera targeting first-quarter 2016 completion.
The fractionator will handle a C3+ NGL mix stream—a mixture of propane, butane, and condensate. This incremental C3+ mix fractionation capacity is in addition to the de-ethanizer currently under construction at KFS (OGJ Online, Sept. 11, 2012), which will allow Keyera to fractionate roughly 30,000 b/d of C2+ mix—ethane, propane, butane, and condensate.
Keyera last year proposed a 12-in. OD condensate pipeline connecting its Alberta Diluent Terminal in Edmonton to its Fort Saskatchewan Pipeline System (OGJ Online, Aug. 2, 2013).
Long-term agreements provide commercial support for the $220-million C3+ project and Keyera is negotiating with other producers for the remaining capacity.
TRANSPORTATION — Quick Takes
Statoil resumes production at Hammerfest LNG
Statoil ASA reported that production from the Hammerfest LNG plant has resumed following a gas leak that occurred Jan. 5 in its processing facility.
"We started run-up of the Hammerfest LNG plant [Jan. 7], and the plant has now reached stable operation. All necessary repairs on the plant have been completed to ensure a safe and efficient start-up," stated Knut Gjertsen, head of Statoil's Snohvit operations.
Additional time for start-up preparations at the plant, which lies on Melkoya Island in northern Norway, was needed because of a condensate leak connected to plant run-up. Statoil said it will investigate the incident.
A series of issues and shut downs has befallen the plant since it first came on stream in 2007 (OGJ Online, Aug. 21, 2007), during which it endured several outages for the remainder of the year and into 2008.
Statoil in 2009 shut the plant down for 3 months for upgrading and maintenance, including the replacement of 15 heat exchangers that form the core of the process that liquefies Snohvit development gas (OGJ Online, Aug. 14, 2009).
Three years later, production was stopped "as a result of water ingression in the natural gas dryers," the Norwegian state-owned company reported (OGJ Online, July 12, 2012). The plant was soon gradually brought back online (OGJ Online, Aug. 3, 2012).
Shell closes on Repsol LNG asset acquisition
Royal Dutch Shell PLC reported the completion of its acquisition of Repsol SA's LNG portfolio outside North America for a reduced net cash purchase price of $3.8 billion. The deal was first reported in February 2013 (OGJ Online, Feb. 26, 2013).
Shell will assume $1.6 billion of balance sheet liabilities relating to existing leases for LNG ship charters.
The company will now undertake an additional 7.2 million tonnes/year of directly managed LNG volumes, encompassing LNG supply in the Atlantic from Trinidad and Tobago, and in the Pacific from Peru.
Specifics of the deal include: Net 4.2 million tpy equity LNG plant capacity, increasing Shell's equity LNG capacity to 26 million tpy from 22 million tpy; Atlantic LNG Trains 1-4; 14.8 million tpy capacity on a 100% basis (20-25% equity for each train); operated by Atlantic LNG Co. of Trinidad & Tobago; Peru LNG 4.45 million tpy capacity, on a 100% basis (acquisition: 20%; equity: 100% offtake), operated by Peru LNG Co.; A fleet of LNG carriers, comprising long-term and short-term time charters; and LNG volumes of 7.2 million tpy through long-term off-take agreements.
As part of this agreement, as previously disclosed, Shell has committed to supply 100,000 tpy of LNG to Repsol's Canaport LNG terminal in Canada over 10 years.
EPP to expand LPG export facility at Oiltanking
Enterprise Products Partners LP (EPP) reported it will further expand its liquefied petroleum gas export terminal at Oiltanking's complex on the Houston Ship Channel (HSC). EPP's expanded LPG terminal is supported by a 50-year service agreement with Oiltanking Partners LP to provide additional dock space and related services.
The expanded LPG export terminal is expected to be in service by yearend 2015 and is supported by long-term LPG export agreements. This expansion is in lieu of a second LPG terminal announced in October 2013 and will result in more capacity than previously anticipated (OGJ Online, Oct. 2, 2013).
Once the expanded facilities are completed, EPP will have aggregate capacity to load more than 16 million bbl/month of low-ethane propane and butane.
"Demand for both current and future LPG exports continues to be strong," said Michael A. Creel, chief executive officer of EPP's general partner.
"The location of the expanded terminal at Oiltanking enables us to increase maximum loading capacity to approximately 27,000 bbl/hr, the highest in the industry, while nominally reducing the overall capital costs associated with the project," Creel said.